PART I
This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section beginning on page 10 of this document for an explanation of these types of statements. We use the terms “Stone,” “Stone Energy,” “Company,” “we,” “us” and “our” to refer to Stone Energy Corporation and its consolidated subsidiaries. Certain terms relating to the oil and gas industry are defined in “Glossary of Certain Industry Terms,” which begins on page G-1 of this Annual Report on Form 10-K (this “Form 10-K”).
ITEM 1. BUSINESS
The Company
Stone Energy is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (the “GOM”) Basin since our incorporation in 1993 and have established technical and operational expertise in this area. We leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific plays of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. At December 31, 2016, we had producing properties and acreage in the Marcellus and Utica Shales in Appalachia. In connection with our restructuring efforts, we determined that a sale of the Appalachia Properties (as defined below) would be a beneficial way to maximize value for all stakeholders. We completed the sale of the Appalachia Properties on February 27, 2017 for net cash consideration of approximately $522.5 million. See “
Reorganization and Emergence from Voluntary Chapter 11 Proceedings
” below for additional information. As of
December 31, 2017
, our estimated proved oil and natural gas reserves were approximately
32.5
MMBoe.
We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have an additional office in New Orleans, Louisiana.
Business Strategy
Our long-term strategy is to grow net asset value through acquiring, discovering, developing and operating a focused set of margin-advantaged properties while appropriately managing financial, exploration and operational risk. Oil and natural gas prices significantly declined in the second half of 2014, and sustained lower prices continued throughout 2015, 2016 and early 2017, with a modest recovery in late 2017. In response to that decline and the uncertainty regarding future commodity prices, we adjusted our near-term strategy and focused on maintaining maximum liquidity. We structured a plan of reorganization to improve our financial position and liquidity and filed voluntary petitions under Chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”) on December 14, 2016 (the “Petition Date”). On February 28, 2017, we emerged from bankruptcy, and in April 2017, our board of directors retained a financial advisor to assist them in determining the Company’s strategic direction. See “
Strategic Review and Pending Combination with Talos
”
below for additional details.
Strategic Review and Pending Combination with Talos
Following the successful completion of our financial restructuring and emergence from Chapter 11 reorganization, our Board of Directors (the “Board”) retained a financial advisor in April 2017 to assist the Board in its determination of the Company’s strategic direction, including assessing its various strategic alternatives. Pursuant to such process, on November 21, 2017, Stone and certain of its subsidiaries entered into a series of related agreements pertaining to a business combination with Talos Energy LLC (“Talos Energy”) and its indirect wholly owned subsidiary Talos Production LLC (“Talos Production” and, together with Talos Energy, “Talos”). Talos Energy is controlled indirectly by entities controlled by Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (together with Apollo VII, “Apollo Management”) and Riverstone Energy Partners V, L.P. (“Riverstone”).
Under the terms of a definitive agreement, Talos and Stone will both become wholly-owned subsidiaries of a new holding company, which at closing will become a publicly traded entity named Talos Energy, Inc. (“New Talos”). The combination involves an all-stock transaction pursuant to which holders of Stone common stock immediately prior to the combination will collectively hold 37% of the outstanding New Talos common stock and the current Talos stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions. The combination is expected to close in the second quarter of 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. For additional details on the Talos combination, see
Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
.
Reorganization and Emergence from Voluntary Chapter 11 Proceedings
On the Petition Date, the Company and its subsidiaries Stone Energy Offshore, L.L.C. (“Stone Offshore”) and Stone Energy Holding, L.L.C. (together with the Company, the “Debtors”)
filed voluntary petitions (the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. On February 15, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the “Plan”), as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017.
Our restructuring included the sale of Stone’s producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the “Appalachia Properties”) to EQT Corporation, through its wholly-owned subsidiary EQT Production Company (“EQT”), on February 27, 2017, for net cash consideration of approximately $522.5 million. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of the Predecessor Company’s (as defined below) total estimated proved oil and natural gas reserves, on a volume equivalent basis. Upon closing of the sale on February 27, 2017, we no longer have operations or assets in Appalachia.
The voluntary reorganization under Chapter 11 substantially reduced our indebtedness and restructured our balance sheet. Upon emergence from bankruptcy, we eliminated approximately $1.1 billion in principal amount of outstanding debt. For additional details on the Chapter 11 proceedings, the sale of the Appalachia Properties and the terms of the Plan, see
Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
.
Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “
Reorganizations
”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. See
Note 3 – Fresh Start Accounting
for further details on the impact of fresh start accounting on the Company’s consolidated financial statements. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.
Board of Director and Management Changes
Pursuant to the Plan, upon the Effective Date, Neal P. Goldman (Chairman of the Board), John “Brad” Juneau, David I. Rainey, Charles M. Sledge, James M. Trimble and David N. Weinstein were appointed as directors of the Board of the Successor Company. In addition, David H. Welch, the President and Chief Executive Officer of the Company at the time of the Effective Date, was reappointed to the Board pursuant to the Plan. Mr. Welch retired as President and Chief Executive Officer of the Company and as a member of the Board on April 28, 2017.
On April 28, 2017, the Board elected James M. Trimble, a member of the Board, to serve as the Company’s Interim Chief Executive Officer and President, and appointed Keith A. Seilhan, the Company’s Senior Vice President – Gulf of Mexico, to serve as the Company’s Chief Operating Officer.
Operational Overview
Gulf of Mexico Basin
We have properties in the deep water of the GOM, as well as limited exposure to GOM conventional shelf and deep gas properties. In 2014, we sold a majority of our GOM conventional shelf properties.
Gulf of Mexico — Deep Water.
We believe that the deep water of the GOM is an attractive area to acquire, explore, develop and operate with high-potential investment opportunities. We have made significant investments in seismic data and leasehold interests and have assembled a technical team with prior geological, geophysical, engineering and operational experience in the deep water arena to evaluate potential exploration, development and acquisition opportunities. Since 2006, we have made two significant acquisitions that included two deep water platforms, producing reserves and numerous leases. We have a portfolio of deep water projects ranging from lower risk development projects incorporating existing facilities to higher risk exploration
prospects that would require a new production facility. We have utilized subsea tie-backs in the deep water on satellite discoveries close to existing facilities, which require less capital and time than new stand-alone facilities. We have higher risk exploration prospects that could expose the company to significant reserves, if successful. Projects in the deep water typically require substantially more time, planning, manpower and capital than an onshore project. Our deep water properties accounted for 86% of our estimated proved oil and natural gas reserves at December 31, 2017, on a volume equivalent basis.
Gulf Coast — Conventional Shelf and Deep Gas.
We have historically focused on the GOM conventional shelf, but after the sale of a majority of our GOM conventional shelf properties in 2014, we have significantly reduced our exposure in this area to primarily two remaining fields, which provide production and cash flow. There are limited exploitation and exploration projects for us on our GOM conventional shelf properties. The Gulf Coast deep gas play (prospects below 15,000 feet) provides us with higher potential exploration opportunities with existing infrastructure nearby, which shortens the lead time to production. Our conventional shelf and deep gas properties accounted for 14% of our estimated proved oil and natural gas reserves at December 31, 2017, on a volume equivalent basis.
Appalachia
Our restructuring included the sale of the Appalachia Properties to EQT on February 27, 2017, for net cash consideration of approximately $522.5 million. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of the Predecessor Company’s total estimated proved oil and natural gas reserves, on a volume equivalent basis. Upon closing of the sale on February 27, 2017, we no longer have operations or assets in Appalachia.
Oil and Gas Marketing
Our oil and natural gas production is sold at current market prices under short-term contracts. Phillips 66 Company and Shell Trading (US) Company accounted for approximately 74% and 15%, respectively, of our oil and natural gas revenue generated during the period from March 1, 2017 through
December 31, 2017
. We do not believe that the loss of any of our major purchasers would result in a material adverse effect on our ability to market future oil and natural gas production. From time to time, we may enter into transactions that hedge the price of oil and natural gas. See
Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.
Competition and Markets
Competition in the GOM Basin and onshore plays is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. See
Item 1A. Risk Factors – Competition within our industry may adversely affect our operations.
The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control, including, but not limited to, the amount of domestic production and imports of foreign oil and exports of liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of oil and natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation and the conduct of drilling operations and federal regulation of oil and natural gas. All of these factors, together with economic factors in the marketing arena, generally may affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.
Regulation
Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations.
Various aspects of our oil and natural gas operations are regulated by certain agencies of the federal government for our operations on federal leases. The jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the unitization or pooling of oil and natural gas properties. In this regard, some agencies can order the pooling or integration of tracts to facilitate exploration while others rely on voluntary pooling of lands and leases. In addition, certain conservation laws establish maximum
rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Outer Continental Shelf Regulation
. Our operations on federal oil and gas leases in the GOM are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Bureau of Ocean Energy Management (“BOEM”). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act. These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf (“OCS”), calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. These rules are frequently subject to change. For example, in April 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “Executive Orders”), respectively, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. On October 24, 2017, BSEE announced, in a report published by the Department of the Interior, that it is considering several revisions to the regulations and that it is in the process of determining the most effective way to engage stakeholders in the process.
Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in connection with its review of exploration and development plans, rights of way and rights of use and/or easement applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Pursuant to the Executive Orders, BOEM is reviewing the proposed air quality rule. On October 24, 2017, the Department of the Interior announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.
Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, under certain circumstances, BSEE may require Stone’s operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.
Furthermore, hurricanes in the GOM can have a significant impact on oil and natural gas operations on the OCS. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. BOEM and BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, BOEM and BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by BOEM and BSEE for future hurricane seasons. New requirements, if any, could increase Stone’s operating costs and/or capital expenditures.
In addition, in order to cover the various decommissioning obligations of lessees on the OCS, BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. Historically, we have been able to obtain an exemption from most bonding requirements based on our financial net worth. However, on March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately
$115 million
in surety bonds in favor of BOEM, third-party bonds, and letters of credit, all relating to our offshore abandonment obligations.
In July 2016, BOEM issued a new notice to lessees and operators (the “NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurance by offshore lessees. The NTL details procedures to
determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of OCS facilities) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.
We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017. BOEM has rescinded that order and all other sole-liability orders (i.e., orders related to properties for which there is no other current or prior owner who is liable) until further notice.
In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when, or if, the July 2016 NTL will be implemented or whether a revised NTL might be proposed. Compliance with the NTL, or any other new rules, regulations, or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, limit our activities in certain areas, cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.
If fully implemented, the July 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations. See
Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
.
Natural Gas
. In 2005, the United States Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (the “NGA”) to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Stone Energy, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the “FERC”), in contravention of rules prescribed by the FERC. In 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. The U.S. Commodity Futures Trading Commission (the “CFTC”) has similar authority with respect to energy futures commodity markets. Stone Energy does not anticipate it will be affected any differently by these requirements than other producers of natural gas.
Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC has undertaken various initiatives to increase competition within the natural gas industry, including requiring interstate pipelines to provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In addition, the natural gas pipeline industry is also subject to state regulations, which may change from time to time in ways that affect the availability, terms and cost of transportation. However, we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competitors.
Oil.
Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the Federal Trade Commission (the “FTC”) issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale, from knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person or intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the FTC Act.
Our sales of crude oil, condensate and natural gas liquids (“NGL”s) are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, NGLs and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.
In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. As it relates to intrastate crude oil, condensate and NGL pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate and NGL pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and NGL producers or marketers.
Miscellaneous
. Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by the United States Congress, state regulatory bodies, BOEM, BSEE, FERC and other federal regulatory bodies and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the oil and natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by BOEM, BSEE, FERC or any other state or federal agency will continue indefinitely.
Environmental Regulation
As a lessee and operator of offshore oil and gas properties in the United States, we are subject to stringent federal, state and local laws and regulations relating to the protection of the environment, worker health and safety, and natural resources, as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations may require us to obtain permits authorizing air emissions and wastewater discharge from operations and can affect the location or size of wells and facilities, limit or prohibit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of substances generated in connection with oil and gas industry operation. The following is a summary of some of the existing laws, rules and regulations to which our business is subject.
Hazardous Substances and Waste Management.
The Resource Conservation and Recovery Act (the “RCRA”) generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. In addition, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes rulemaking for revised oil and gas regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.
Comprehensive Environmental Response, Compensation and Liability Act.
The Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”, or the “Superfund Law”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under the Superfund Law for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used in operations related to the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such substances have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose storage, treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing strict, joint and several liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.
Oil Pollution Act.
The Oil Pollution Act of 1990 (“OPA”) holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, BOEM has finalized rules raising OPA’s damages liability cap from $75 million to $134 million. OPA also requires responsible parties to maintain evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between $35 million to $150 million for companies operating on the OCS, although BOEM may increase this amount in certain situations. From time to time, the United States Congress has proposed amendments to OPA raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.
National Environmental Policy Act
. The National Environmental Policy Act (“NEPA”) requires federal agencies, including the Department of the Interior, to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment. These requirements can lead to additional costs and delays in permitting for operators as the Department of the Interior or its bureaus may need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in support of its leasing and other activities that have the potential to significantly affect the quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in delaying the permitting and development of projects, and result in increased costs.
Climate Change.
From time to time, the United States Congress has considered a variety of tax, energy-related or environmental market-based mechanisms to promote or induce the reduction of emissions of greenhouse gases (“GHGs”) by several commercial or industrial sectors. In addition, more than one half of the states already have begun implementing legal measures such as renewable energy requirements or cap and trade programs to reduce emissions of GHGs.
Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement entered into force on November 4, 2016. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement,
but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
In addition, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act (the “CAA”). The EPA adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources through preconstruction and operating permit requirements. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, on an annual basis.
Recent regulation of GHGs has focused on fugitive methane emissions. For example, in June 2016, the EPA finalized rules that established new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. The regulations will remain in effect unless revised or repealed by separate EPA rulemaking in the future, which is likely to be challenged in court.
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 to comply with new regulatory or reporting requirements. Substantial limitations on greenhouse gas emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. 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 GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of operations. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Water discharges.
Stone’s discharges into waters of the United States are limited by the federal Clean Water Act (“CWA”) and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving some non-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans.
Air emissions.
The CAA and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants, and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. 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.
Worker Health and Safety
. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information
about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
Endangered Species
. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit, though, in December 2017, the U.S. Fish and Wildlife Service (the “USFWS”) provided guidance limiting the reach of the MBTA. The Marine Mammal Protection Act similarly prohibits the taking of marine mammals without authorization. We conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Historically, our compliance costs for the protection of marine species 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 USFWS or the National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas.
We have made, and will continue to make, expenditures on a regular basis relating to environmental compliance. Although we maintain pollution insurance to cover a portion of the costs of cleanup operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To date, we believe that our expenditures related to compliance with existing environmental requirements has not had a material effect on our results of operations or financial condition. However, we also believe that it is reasonably likely that the historical trend in environmental legislation and regulation will continue toward stricter standards and, thus, we cannot give any assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production, and may have a material adverse impact on our results of operations and financial condition.
We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the United States. We employ a safety, environmental and regulatory department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions and track regulatory developments applicable to our operations, such as the ones described in the paragraphs above.
Employees
On
March 9, 2018
, we had 158 full-time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. We utilize the services of independent contractors to perform various daily operational duties.
Available Information
We make available free of charge on our Internet website (www.stoneenergy.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). We also make available on our Internet website our Code of Business Conduct and Ethics, Corporate Governance Guidelines and Audit, Compensation, Nominating & Governance, Reserves and Safety Committee Charters, which have been approved by our Board. Copies of these documents are also available free of charge by writing to us at: Chief Financial Officer, Stone Energy Corporation, P.O. Box 52807, Lafayette, LA 70505. The annual CEO certification required by Section 303A.12 of the New York Stock Exchange Listed Company Manual was submitted on December 14, 2017.
Financial Information
Our financial information is included in the consolidated financial statements and the related notes beginning on page F-1.
Forward-Looking Statements
The information in this Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Exchange Act. All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.
Forward-looking statements may appear in a number of places in this Form 10-K and include statements with respect to, among other things:
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expected results from risk-weighted drilling activities;
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estimates of our future oil and natural gas production, including estimates of any increases in oil and natural gas production;
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planned capital expenditures and the availability of capital resources to fund capital expenditures;
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our outlook on oil and natural gas prices;
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estimates of our oil and natural gas reserves;
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any estimates of future earnings growth;
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the impact of political and regulatory developments;
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our outlook on the resolution of pending litigation and government inquiry;
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estimates of the impact of new accounting pronouncements on earnings in future periods;
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our future financial condition or results of operations and our future revenues and expenses;
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the outcome of restructuring efforts and asset sales;
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the amount, nature and timing of any potential acquisition or divestiture transactions;
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any expected results or benefits associated with our acquisitions;
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our access to capital and our anticipated liquidity;
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estimates of future income taxes;
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our business strategy and other plans and objectives for future operations, including the Board’s assessment of the Company’s strategic direction;
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our ability to consummate our proposed combination transaction with Talos; and
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the timing of the consummation of the proposed combination transaction with Talos.
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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:
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commodity price volatility, including further or sustained declines in the prices we receive for our oil and natural gas production;
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domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;
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the availability of capital on economic terms to fund our operations, capital expenditures, acquisitions and other obligations;
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our future level of indebtedness, liquidity and compliance with debt covenants;
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our future financial condition, results of operations, revenues, cash flows and expenses;
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t
he potential need to sell certain assets or raise additional capital;
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our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by BOEM;
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declines in the value of our oil and gas properties resulting in a decrease in the borrowing base under our bank credit facility and impairments;
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our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
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the impact of a financial crisis on our business operations, financial condition and ability to raise capital;
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the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
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third-party interruption of sales to market;
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lack of availability and cost of goods and services;
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market conditions relating to potential acquisition and divestiture transactions;
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regulatory and environmental risks associated with drilling and production activities;
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our ability to establish operations or production on our acreage prior to the expiration of related leaseholds;
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availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;
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competition in the oil and gas industry;
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our inability to retain and attract key personnel;
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drilling and other operating risks, including the consequences of a catastrophic event;
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unsuccessful exploration and development drilling activities;
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hurricanes and other weather conditions;
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availability, cost and adequacy of insurance coverage;
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adverse effects of changes in applicable tax, environmental, derivatives, permitting, bonding and other regulatory requirements and legislation, as well as agency interpretation and enforcement and judicial decisions regarding the foregoing;
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uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and
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other risks described in this Form 10-K.
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Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
ITEM 1A. RISK FACTORS
Our business is subject to a number of risks including, but not limited to, those described below:
Risks Relating to the Pending Talos Combination
The Transactions may not be completed on the terms or timeline currently contemplated, or at all, and failure to complete the Transactions may result in material adverse consequences to our business and operations.
The transactions contemplated by the Transaction Agreement (the “Transaction Agreement”), dated as of November 21, 2017, among Stone, certain of Stone’s subsidiaries, Talos Energy, and Talos Production (the “Transactions”) are subject to several closing conditions, including, among others, the following:
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receipt of the approval of our shareholders;
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receipt of clearances and approvals under the rules of antitrust and competition law authorities in the United States;
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the absence of any law or order prohibiting the consummation of the Transactions;
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receipt of governmental consents and approvals;
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the effectiveness of the registration statement on Form S-4, and any amendment thereof, filed in connection with the Talos combination, and there being no pending or threatened stop order relating thereto;
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approval for listing on the New York Stock Exchange (the “NYSE”) of the shares of New Talos common stock issuable pursuant to the Transaction Agreement;
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the satisfaction of closing conditions of the Debt Exchange Agreement, dated as of November 21, 2017, by and among Talos Production, Talos Production Finance Inc., Stone, New Talos and the lenders and noteholders listed on the schedules thereto, including the ability to contemporaneously close such transactions with the other transactions to occur at closing;
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the consummation of a tender offer and consent solicitation pursuant to which the holders of a majority of the Company’s 7 ½% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) (excluding the 2022 Second Lien Notes held by Franklin Advisers, Inc. (“Franklin”) and MacKay Shields LLC (“MacKay Shields”) on behalf of their clients and managed funds) will have been tendered for the consideration offered thereunder and the effectiveness of a supplemental indenture to the indenture governing the 2022 Second Lien Notes that eliminates substantially all of the restrictive covenants in such indenture; and
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the satisfaction of closing conditions of the Support Agreement, dated as of November 21, 2017, by and among Stone, New Talos, Apollo Management and Riverstone, and the ability to contemporaneously close such transactions with the other transactions to occur at closing.
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If any one of these conditions is not satisfied or waived, the Transactions may not be completed. There is no assurance that the Transactions will be completed on the terms or timeline currently contemplated, or at all.
Governmental or regulatory agencies could impose conditions on the completion of the Transactions or require changes to the terms of the Transaction Agreement or other agreements to be entered into in connection with the Transactions. Such conditions or changes could have the effect of delaying or impeding the completion of the Transactions. If these approvals are not received, then neither Stone nor Talos Energy will be obligated to complete the Transactions.
If our stockholders do not adopt the Transaction Agreement or if the Transactions are not completed for any other reason, we would be subject to a number of risks, including the following:
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we will be required to pay our costs related to the Transactions, such as legal, accounting, financial advisory, and printing fees, whether or not the Transactions are completed;
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our management has committed time and resources to matters relating to the Transactions that otherwise could have been devoted to pursuing other beneficial opportunities;
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we and our stockholders would not realize the anticipated strategic benefits of the Transactions;
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we may be required to pay a termination fee and to reimburse transaction expenses to Talos Energy if the Transaction Agreement is terminated under certain circumstances;
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the potential occurrence of litigation related to any failure to complete the Transactions;
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if the Transaction Agreement is terminated and our Board seeks another business combination, our stockholders cannot be certain that we will be able to find a party willing to enter into a transaction agreement on terms equivalent to or more attractive than the terms in the Transaction Agreement; and
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the trading price of our common stock may decline or experience increased volatility to the extent that the current market prices reflect a market assumption that the Transactions will be completed.
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The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price of our common stock. We are also exposed to general competitive pressures and risks, which may be increased if the Transactions are not completed.
We will be subject to business uncertainties and contractual restrictions while the Transactions are pending that could adversely affect us.
Uncertainty about the effect of the Transactions on our employees and our business relationships may have an adverse effect on us, regardless of whether the Transactions are eventually completed. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Transactions are completed, or the Transaction Agreement is terminated, and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships with Stone or to delay or defer certain business decisions.
The pursuit of the Transactions and the preparation for our potential integration with Talos Energy have placed, and will continue to place, a significant burden on the management and internal resources of Stone. There is a significant degree of difficulty and management distraction inherent in the process of closing the Transactions and integrating Stone and Talos Energy, which could cause an interruption of, or loss of momentum in, the activities of our existing business, regardless of whether the Transactions are eventually completed. Before and immediately following closing, our management team will be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. One potential consequence of such distractions could be the failure of management to realize other opportunities that could be beneficial to Stone. If our management is not able to effectively manage the process leading up to and immediately following closing, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
Under the terms of the Transaction Agreement, we are subject to certain restrictions on the conduct of our business until the earlier of the effective time of the combination or the termination of the Transaction Agreement, which may adversely affect our ability to execute certain of our business strategies, including the ability in certain cases to enter into contracts, acquire or dispose of assets, incur indebtedness or incur capital expenditures, as applicable. Such limitations could negatively affect our business and operations prior to the completion of the Transactions.
The Transaction Agreement contains provisions that may discourage other companies from trying to acquire Stone.
The Transaction Agreement contains provisions that may discourage third parties from submitting business combination proposals to Stone that might result in greater value to our stockholders than the Transactions. The Transaction Agreement generally prohibits us from soliciting any competing proposal. In addition, if the Transaction Agreement is terminated by us in circumstances that obligate us to pay a termination fee and to reimburse transaction expenses to Talos Energy, our financial condition may be adversely affected as a result of the payment of the termination fee and reimbursement of transaction expenses, which might deter third parties from proposing alternative business combination proposals.
Completion of the Transactions may trigger change in control or other provisions in certain agreements to which Stone is a party.
The completion of the Transactions may trigger change in control or other provisions in certain agreements to which Stone is a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to Stone.
Risks Relating to our Reorganization
The Plan was based in large part upon assumptions and analyses developed by us. Our actual financial results may vary materially from the projections that we filed in connection with the Plan. If these assumptions and analyses prove to be incorrect, the Plan may be unsuccessful in its execution.
The Plan affected both our capital structure and the ownership, structure and operation of our business and reflected assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we considered appropriate under the circumstances. In addition, the Plan relied upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. The financial projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that were the basis of these financial forecasts will not be accurate. In our case, the forecasts were even more speculative than normal, because they involved fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by the Plan will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our business or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of the Plan.
Our historical financial information may not be indicative of our future financial performance.
On February 28, 2017, the effective date of our emergence from bankruptcy, we adopted fresh start accounting and consequently, our assets and liabilities were adjusted to fair values and our accumulated deficit was restated to zero. Accordingly, our financial condition and results of operations following our emergence from Chapter 11 will not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, as a result of the implementation of the Plan and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
Funds advised by two significant stockholders currently hold approximately 36% and 20%, respectively, of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.
Business Risks
Oil and natural gas prices are volatile. Significant declines in commodity prices in the future may adversely affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.
Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our bank credit facility and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Oil and natural gas prices significantly declined in second half of 2014, and sustained lower prices continued throughout 2015, 2016 and early 2017. Despite a modest recovery in late 2017, commodity prices could remain suppressed or decline further, which will likely have material adverse effects on the value of our estimated proved reserves and our borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take additional ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See
“—Lower oil and natural gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.”
In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.
The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:
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changes in the supply of and demand for oil and natural gas;
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level of consumer product demands;
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hurricanes and other weather conditions;
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domestic and foreign governmental regulations and taxes;
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price and availability of alternative fuels;
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political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa;
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actions by the Organization of Petroleum Exporting Countries;
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U.S. and foreign supply of oil and natural gas;
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price and quantity of oil and natural gas imports and exports;
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the level of global oil and natural gas exploration and production;
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the level of global oil and natural gas inventories;
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localized supply and demand fundamentals and transportation availability;
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speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
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price and availability of competitors’ supplies of oil and natural gas;
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technological advances affecting energy consumption; and
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overall domestic and foreign economic conditions.
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These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.
Our debt level and the covenants in the current and any future agreements governing our debt could negatively impact our financial condition, results of operations and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.
The terms of the current agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:
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incurring additional debt;
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paying dividends on stock, redeeming stock or redeeming subordinated debt;
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creating liens on our assets;
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guaranteeing other indebtedness;
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entering into agreements that restrict dividends from our subsidiary to us;
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merging, consolidating or transferring all or substantially all of our assets;
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hedging future production; and
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entering into transactions with affiliates.
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Our level of indebtedness, and the covenants contained in current and future agreements governing our debt could have important consequences on our operations, including:
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requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
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limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;
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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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detracting from our ability to successfully withstand a downturn in our business or the economy generally;
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placing us at a competitive disadvantage against other less leveraged competitors; and
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making us vulnerable to increases in interest rates because debt under our bank credit facility is at variable rates.
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We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Lower commodity prices have negatively impacted our revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which declined significantly since mid-2014.
We depend on our bank credit facility for a portion of our future capital needs. We are required to comply with certain debt covenants and ratios under our bank credit facility. Our borrowing base under our bank credit facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing base, our outstanding bank credit facility borrowings plus our outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our current agreement with the banks allows us to cure a borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the borrowing base deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after our written election to do so and/or (3) pay the deficiency in six equal monthly installments.
We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our debt, including our bank credit facility and the indenture governing the 2022 Second Lien Notes, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through offerings of our capital stock, a refinancing of
our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing or sale of assets will be successfully completed.
Regulatory requirements and permitting procedures imposed by BOEM and BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.
BOEM and BSEE have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the GOM and, as a result, are continuing to develop and implement new, more restrictive requirements. For example, in April 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “Executive Orders”), respectively, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. On October 24, 2017, BSEE announced, in a report published by the Department of the Interior, that it is considering several revisions to the regulations and that it is in the process of determining the most effective way to engage stakeholders in the process.
Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in connection with its review of exploration and development plans, rights of way and rights of use, and/or easement applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Pursuant to the Executive Orders, BOEM is reviewing the proposed air quality rule. On October 24, 2017, the Department of the Interior announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.
Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Furthermore, among other adverse impacts, new regulatory requirements could delay operations, disrupt our operations or increase the risk of leases expiring before exploration and development efforts have been completed due to the time required to develop new technology. This would result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or shut-in production at one or more of our facilities. If material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.
New guidelines recently issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS may have a material adverse effect on our business, financial condition, or results of operations.
BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we have been able to obtain an exemption from most bonding requirements based on our financial net worth. On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately
$115 million
in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.
In July 2016, BOEM issued a new NTL, with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurance by offshore lessees. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of OCS facilities) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.
We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017. BOEM has rescinded that order and all other sole-liability orders (i.e., orders related to properties for which there is no other current or prior owner who is liable) until further notice.
In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when, or if, the July 2016 NTL will be implemented or whether a revised NTL might be proposed. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, limit our activities in certain areas, cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.
In addition, if fully implemented, the July 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. Moreover, depressed oil prices could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and Stone cannot provide assurance that it will be able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and may require us to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.
A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our current bank credit facility or in the capital markets.
Historically, we have used our cash flows from operating activities and borrowings under our bank credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. In the future, we may not be able to access adequate funding under our bank credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our bank credit facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts and the requirement by contractual counterparties of us to post collateral guaranteeing performance.
We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.
We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our credit facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling
results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital are subject to a number of variables, including:
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the level of hydrocarbons we are able to produce from our wells;
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the prices at which our production is sold;
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our ability to acquire, locate and produce new reserves; and
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our ability to borrow under our credit facility.
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If low oil and natural gas prices, operating difficulties, declines in reserves or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities and the borrowing base under our credit facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices since mid-2014.
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.
Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area in the GOM. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the GOM and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:
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severe weather, such as hurricanes and other adverse weather conditions;
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delays or decreases in production, the availability of equipment, facilities or services;
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delays or decreases in the availability or capacity to transport, gather or process production;
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changes in the status of pipelines that we depend on for transportation of our production to the marketplace;
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extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage or require posting substantial bonds to address decommissioning and plugging and abandonment costs and interruption or termination of operations by governmental authorities based on environmental, safety, or other considerations; and/or
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changes in the regulatory environment such as the new guidelines recently issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS.
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Because all or a number of our properties could experience many of the same conditions at the same time, these conditions have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.
We may experience significant shut-ins and losses of production due to the effects of hurricanes in the GOM.
Our production is exclusively associated with our properties in the GOM and the U.S. Gulf Coast. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the GOM. In past years, we have experienced shut-ins and losses of production due to the effects of hurricanes in the GOM. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses.
A significant part of our production and estimated proved reserves are concentrated in one field.
As of and for the year ended December 31, 2017, approximately 65% of our estimated proved reserves and 53% of our production on a volume equivalent basis, respectively, were derived from our Pompano properties. Accordingly, if the level of production from these properties substantially declines, or is affected by a pipeline shut-in, it could have a material adverse effect on our overall production level and our revenue. If the actual reserves associated with these properties are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are not insured against all of the operating risks to which our business is exposed.
In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, oil pollution, construction all risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.
Currently, we have general liability insurance coverage with an annual aggregate limit of $837.5 million on a 100% working interest basis. We no longer purchase physical damage insurance coverage for our platforms for losses resulting from named windstorms. Additionally, we now purchase physical damage insurance coverage for losses resulting from operational activities for only our Amberjack and Pompano platforms. We have continued purchasing physical damage insurance coverage for operational losses for a selected group of pipelines, including the majority of the pipelines and umbilicals associated with our Amberjack and Pompano facilities.
Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20 million to $500 million per occurrence. Exploratory deep water wells have a control of well coverage limit of up to $600 million per occurrence. Additionally, we currently maintain $70 million in oil pollution liability coverage. Our operational control of well and physical damage policy limits are scaled proportionately to our working interests. Our general liability program utilizes a combination of for assureds interest and scalable limits. All of our policies described above are subject to deductibles, sub-limits or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider, subject to the application of various states’ laws.
An operational or hurricane-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. In past years, we have experienced production interruptions for which we had no production interruption insurance.
We reevaluate the purchase of insurance, policy limits and terms annually in May through July. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the GOM, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.
Lower oil and natural gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.
We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing twelve-month average, hedge-adjusted commodity price and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the estimated discounted future net
cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. For example, oil and natural gas prices significantly declined in the second half of 2014, and sustained lower prices continued throughout 2015, 2016 and early 2017, with a modest recovery in late 2017. We recorded non-cash ceiling test write-downs of approximately $1,362 million and $357 million for the years ended December 31, 2015 and 2016, respectively, and $256 million during the period of March 1, 2017 through December 31, 2017. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Our oil and gas operations are subject to various U.S. federal, state and local governmental regulations that materially affect our operations.
Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can release materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms and conditions related to the purchase and sale of natural gas or crude oil; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations.
In addition, the OPA requires operators of offshore facilities such as us to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other environmental statutes such as CERCLA and RCRA and analogous state laws, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. Consequently, a substantial spill from one of our facilities subject to laws such as the OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.
We may not be able to replace production with new reserves.
In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. GOM reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.
Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions have adversely impacted our ability to obtain financing to fund acquisitions, and they have lowered the level of activity and depressed values in the oil and natural gas property sales market.
Production periods or reserve lives for GOM properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.
High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the GOM during the initial few years when compared to other regions in the United States. Typically, 50% of the reserves of properties in the GOM are depleted within three to four years with natural gas wells having a higher rate of depletion than oil wells. Due to high initial production rates, production of reserves from reservoirs in the GOM generally decline more rapidly than from other producing reservoirs. Our current operations are exclusively in the GOM
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As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our
expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas.
Our actual recovery of reserves may substantially differ from our proved reserve estimates.
This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Form 10-K and the information incorporated by reference. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that any present value of future net cash flows from our proved reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at
December 31, 2017
on historical twelve-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as:
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the amount and timing of actual development expenditures and decommissioning costs;
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the rate and timing of production;
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changes in governmental regulations or taxation;
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volume, pricing and duration of our oil and natural gas hedging contracts;
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supply of and demand for oil and natural gas;
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actual prices we receive for oil and natural gas; and
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our actual operating costs in producing oil and natural gas.
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At
December 31, 2017
, approximately 13% of our estimated proved reserves (by volume) were undeveloped and approximately 26% were non-producing. Any or all of our proved undeveloped or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumptions that we will incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present will produce in economic quantities.
We rely on 3D seismic data to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities, and seismic indications of hydrocarbon saturation may not be reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.
SEC rules could limit our ability to book additional proved undeveloped reserves (“PUDs”) in the future.
SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our proved undeveloped reserves if we do not drill those wells within the required five-year time frame.
Our acreage must be drilled before lease expiration in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.
Unless production is established as required by the leases covering our undeveloped acres, the leases for such acreage may expire. We have leases on 17,280 gross acres (17,280 net) that could potentially expire during fiscal year 2018. See
Item 2. Properties – Productive Well and Acreage Data
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Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling, therefore there is additional risk of expirations occurring in those sections.
The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.
The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of these gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state and local regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
Our actual production could differ materially from our forecasts.
From time to time, we provide forecasts of expected quantities of future oil and natural gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this Item 1A occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.
Our operations are subject to numerous risks of oil and gas drilling and production activities.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the GOM deep water and/or in the Gulf Coast deep gas, our drilling activities could become more expensive. In addition, the geological complexity of GOM deep water, Gulf Coast deep gas and various onshore formations may make it more difficult for us to sustain our historical rates of drilling success. Oil and gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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hurricanes and other weather conditions;
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shortages in experienced labor; and
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shortages or delays in the delivery of equipment.
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The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of
our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.
Our industry experiences numerous operating risks.
The exploration, development and production of oil and gas properties involves a variety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We may also be involved in drilling operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions, including the effects of hurricanes.
In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.
We explore for oil and natural gas in the deep waters of the GOM (water depths greater than 2,000 feet)
.
Exploration for oil or natural gas in the deepwater of the GOM generally involves greater operational and financial risks than exploration on the GOM conventional shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. For example, the drilling of deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower waters. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the GOM conventional shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.
If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations. Any of these industry operating risks could have a material adverse effect on our business, results of operations, and financial condition.
Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.
We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working
in waters of various depths. Estimating future restoration and removal costs in the GOM is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the GOM, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. Also, the sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.
The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled, rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.
Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the GOM following BSEE’s issuance of an NTL that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, which are platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the GOM. The idle iron NTL requires decommissioning of any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities, which must then be permanently plugged or temporarily abandoned within three years’ time. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. We may have to draw on funds from other sources to satisfy decommissioning costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations. Moreover, as a result of the implementation of the idle iron NTL, there is expected to be increased demand for salvage contractors and equipment operating in the GOM, resulting in increased estimates of plugging, abandonment and removal costs and associated increases in operators’ asset retirement obligations.
In addition, we could become responsible for decommissioning liabilities related to offshore facilities we no longer own or operate. Federal regulations allow the government to call upon predecessors-in-interest of oil and gas leases to pay for plugging and abandonment, restoration, and decommissioning obligations if the current operator fails to fulfill those obligations, the costs of which could be significant. Moreover, several onshore and offshore exploration and production companies have sought bankruptcy protection over the past several years. The government may seek to impose a bankrupt entity’s plugging and abandonment obligations on Stone or other predecessors-in-interest, which could be significant and adversely affect our business, results of operations, financial condition and cash flows.
We may not receive payment for a portion of our future production.
We may not receive payment for a portion of our future production. We have attempted to diversify our sales and obtain credit protections, such as parental guarantees, from certain of our purchasers. The tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are unable to predict what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.
There are uncertainties in successfully integrating our acquisitions.
Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results.
Competition within our industry may adversely affect our operations.
Competition within our industry is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the
current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.
Our Certificate of Incorporation and Bylaws and the Delaware General Corporation Law have provisions that, alone or in combination with each other, discourage corporate takeovers and could prevent stockholders from realizing a premium on their investment.
Certain provisions of our Certificate of Incorporation and Bylaws and the provisions of the Delaware General Corporation Law may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our Board rather than pursue non-negotiated takeover attempts. Our Certificate of Incorporation authorizes our Board to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as our Board may determine. Additional provisions of our Certificate of Incorporation and of the Delaware General Corporation Law, alone or in combination with each other, include restrictions on business combinations and the availability of authorized but unissued common stock. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.
We may issue shares of preferred stock with greater rights than our common stock.
Our Certificate of Incorporation authorizes our Board to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights or voting rights. If we issue preferred stock, it may adversely affect the market price of our common stock.
Resolution of litigation could materially affect our financial position and results of operations.
We have been named as a defendant in certain lawsuits. In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods. See
Item 3. Legal Proceedings
for additional information.
Tax laws and regulations may change over time, including the elimination of federal income tax deductions currently available with respect to oil and gas exploration and development.
Tax laws and regulations are highly complex and subject to interpretation, and the tax laws and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various jurisdictions at the time that the filings were made. If these laws or regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws and regulations, it could have a material adverse effect on our business and financial condition.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that significantly reforms the Internal Revenue Code of 1986, as amended. Among other changes, the Tax Act (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses generated after 2017 and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we have not yet had enough time to complete a full analysis of the impact of all changes under the Tax Act. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and any such changes in our interpretations or assumptions could have an adverse effect on our financial position, results of operations and cash flows.
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.
The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases contribute to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources through preconstruction and operating permit requirements.
The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, on an annual basis. Recent regulation of emissions of greenhouse gases has focused on fugitive methane emissions. For example, in June 2016, the EPA finalized rules that establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. The regulations will remain in effect unless revised or repealed by separate EPA rulemaking in the future, which is likely to be challenged in court.
In addition, while the United States Congress has not taken any legislative action to reduce emissions of greenhouse gases, many states have established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets. The Paris Agreement entered into force on November 4, 2016. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to greenhouse gases. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Furthermore, in response to President Trump’s announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
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 to comply with new regulatory or reporting requirements. Substantial limitations on greenhouse gas emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. 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.
In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damage, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
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, floods and other climatic events. Our offshore operations will be particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of
operations. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
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 (the “Act”), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC and the SEC to promulgate rules and regulations implementing the 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 one of its rulemaking proceedings still pending under the Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. 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 will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to 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 into to hedge our commercial risks, the application of the 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 flows.
The full impact of the 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 Act and any new 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 Act and regulations implementing the Act, 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. Finally, the Act was intended, in part, to reduce the volatility of oil and 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 Act and implementing 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 have implemented and continue to implement new regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become directly subject to such regulations and in any event the global derivatives market will be affected to the extent that foreign counterparties are affected by such regulations. At this time, the impact of such regulations is not clear.
Hedging transactions may limit our potential gains.
In order to manage our exposure to price risks in the marketing of our oil and natural gas, we periodically enter into oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedging policy provides that not more than 60% of our estimated production quantities can be hedged for any given month without the consent of the Board. Additionally, a minimum of 25% of each month’s production will not be committed to any hedge contract regardless of the price available. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
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our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;
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there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
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the counterparties to our futures contracts fail to perform the contracts;
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a sudden, unexpected event materially impacts oil or natural gas prices; or
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we are unable to market our production in a manner contemplated when entering into the hedge contract.
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Currently, all of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our bank credit facility. Our existing derivative agreements with the lenders are secured by the security documents executed by the parties under our bank credit facility. Future collateral requirements for our commodity hedging activities are uncertain and will depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.
Terrorist attacks aimed at our facilities could adversely affect our business.
The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our financial condition and operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
As of December 31, 2017, our property portfolio consisted primarily of eight active properties and 34 primary term leases in the GOM Basin. In connection with our restructuring efforts, we sold the Appalachia Properties on February 27, 2017. We no longer have operations or assets in Appalachia. See
Item 1. Business – Operational Overview
. The properties that we currently operate accounted for 94% of our year-end
2017
estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities. Information on our significant properties is included below.
Oil and Natural Gas Reserves
Our Reserves Committee Charter provides that the reserves committee has the sole authority to recommend to our Board appointments or replacements of one or more firms of independent reservoir engineers and geoscientists. The reserves committee reviews annually the arrangements of the independent reservoir engineers and geoscientists with management, including the scope and general extent of the examination of our reserves, the reports to be rendered, the services and fees and consideration of the independence of such independent reservoir engineers and geoscientists. The reserves committee may consult with management but may not delegate these responsibilities. The reserves committee provides oversight in regards to the reserve estimation process but not the actual determination of estimated proved reserves. Our Reserves Committee Charter provides that it is the duty of management and not the duty of the reserves committee to plan or conduct reviews or to determine that our reserve estimates are complete and accurate and are in accordance with generally accepted engineering standards and applicable rules and regulations of the SEC. Our Vice President – Exploration and Business Development is the in-house person designated as primarily responsible for the process of reserve preparation. He is a petroleum engineer with over 20 years of experience in reservoir engineering and analysis. His duties include oversight of the preparation of quarterly reserve estimates and coordination with the outside engineering consultants on the preparation of year-end reserve estimates. The year-end reserve estimates prepared by our outside engineering firm are independent of any oversight of the Vice President – Exploration and Business Development or the reserves committee.
Estimates of our proved reserves at
December 31, 2017
were independently prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI letter, which is filed as an exhibit to this Form 10-K, were Lily W. Cheung, Vice President and Team Leader, and Edward C. Roy III, Vice President. Ms. Cheung is a Registered Professional Engineer in the State of Texas (License No. 107207). Ms. Cheung joined NSAI in 2007 after serving as an Engineer at ExxonMobil Production Company. Ms. Cheung’s areas of specific expertise include estimation of oil and gas reserves, drilling and workover prospect evaluation, and economic evaluations. Ms. Cheung received an MBA degree from University of Texas at Austin in 2007 and a BS degree in Mechanical Engineering from Massachusetts Institute of Technology in 2003. Mr. Roy is a Registered Professional Geoscientist in the State of Texas (License No. 2364). Mr. Roy joined NSAI in 2008 after serving as a Senior Geologist at Marathon Oil Company. Mr. Roy’s areas of specific
expertise include deep-water stratigraphy, seismic interpretation and attribute analysis, volumetric reserve estimation, and probabilistic analysis. Mr. Roy received a MS degree in Geology from Texas A&M University in 1998 and a BS degree in Geology from Texas Christian University in 1992. Ms. Cheung and Mr. Roy both meet or exceed the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
The following table sets forth our estimated proved oil and natural gas reserves (all of which are located in the GOM) as of
December 31, 2017
(Successor). The
2017
average twelve-month oil and natural gas prices, net of differentials, were
$50.05
per Bbl of oil,
$22.90
per Bbl of NGLs and
$2.34
per Mcf of natural gas.
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Oil
(MBbls)
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NGLs
(MBbls)
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Natural Gas
(MMcf)
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Oil, Natural
Gas and
NGLs
(MBoe)
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Reserves Category:
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PROVED
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Developed
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20,275
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1,689
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37,946
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28,288
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Undeveloped
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1,601
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616
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12,170
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4,245
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TOTAL PROVED
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21,876
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2,305
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50,116
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32,533
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At
December 31, 2017
(Successor), we reported estimated PUDs of 4.2 MMBoe, which accounted for 13% of our total estimated proved oil and natural gas reserves, tied to a projected two new wells. Drilling was in progress at December 31, 2017 on one of the new PUD wells, and the other is projected to be drilled in 2018. SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. Neither of these two PUD wells will have been on our books in excess of five years at the time of their scheduled drilling. The following table discloses our progress toward the conversion of PUDs during
2017
.
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Oil, Natural
Gas and
NGLs
(MBoe)
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Future
Development
Costs
(in thousands)
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PUDs beginning of year (Predecessor)
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10,815
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$
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128,972
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Revisions of previous estimates
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(5,282
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)
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(78,701
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)
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Conversions to proved developed reserves
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(1,288
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(19,641
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)
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Additional PUDs added
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—
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—
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PUDs end of year (Successor)
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4,245
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$
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30,630
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During 2017, we invested approximately $19.6 million to convert 1.3 MMBoe of PUDs to proved developed reserves in the GOM. The revisions of previous estimates reflected in the table above were primarily related to the reclassification of one PUD well as a result of the five year limitation based on changes to the development plan for this well subsequent to our emergence from bankruptcy.
The following table includes production and estimated proved reserves associated with our significant properties:
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December 31, 2017
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|
|
|
|
|
2017
|
|
Estimated
|
|
|
|
Field Name
|
|
Location
|
|
Production
(MBoe)
|
|
Proved Reserves
(MBoe)
|
|
Nature of
Interest
|
|
Pompano (1)
|
|
GOM Deep Water
|
|
4,211
|
|
|
21,074
|
|
|
Working
|
|
Mississippi Canyon Block 109
|
|
GOM Deep Water
|
|
995
|
|
|
6,828
|
|
|
Working
|
|
|
|
|
(1)
|
Production volumes and estimated proved reserves include the Pompano and Cardona fields, both of which tie back to the Pompano platform.
|
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein only represents estimates. Reserve engineering is a subjective process of estimating underground accumulations
of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels, operating costs, development costs and income taxes that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions upon which they are based.
As an operator of domestic oil and gas properties, we have filed U.S. Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage ownership (
i.e.
, reserves are reported on a gross operated basis, rather than on a net interest basis) or non-operated wells in which it owns an interest.
Acquisition, Production and Drilling Activity
Acquisition and Development Costs.
The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States and Canada during the periods indicated (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
2016
|
|
2015
|
|
Acquisition costs, net of sales of unevaluated properties
|
$
|
(8,371
|
)
|
|
|
$
|
(324
|
)
|
|
$
|
3,425
|
|
|
$
|
(17,020
|
)
|
|
Exploratory costs
|
12,079
|
|
|
|
2,055
|
|
|
20,059
|
|
|
112,936
|
|
|
Development costs (1)
|
33,356
|
|
|
|
12,547
|
|
|
102,665
|
|
|
266,982
|
|
|
Subtotal
|
37,064
|
|
|
|
14,278
|
|
|
126,149
|
|
|
362,898
|
|
|
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements
|
10,418
|
|
|
|
5,500
|
|
|
47,866
|
|
|
68,410
|
|
|
Total additions to oil and gas properties, net
|
$
|
47,482
|
|
|
|
$
|
19,778
|
|
|
$
|
174,015
|
|
|
$
|
431,308
|
|
|
|
|
|
(1)
|
Includes net changes in capitalized asset retirement costs of
($17,446)
,
$0
,
($4,461)
and
($43,901)
for the period March 1, 2017 through
December 31, 2017
(Successor), the period January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31,
2016
and
2015
(Predecessor), respectively.
|
Production Volumes, Sales Price and Cost Data.
The following table sets forth certain information regarding our production volumes, sales prices and average production costs for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Production:
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
4,169
|
|
|
|
908
|
|
|
6,308
|
|
|
5,991
|
|
|
Natural gas (MMcf)
|
7,616
|
|
|
|
5,037
|
|
|
29,441
|
|
|
36,457
|
|
|
NGLs (MBbls)
|
403
|
|
|
|
408
|
|
|
2,183
|
|
|
2,401
|
|
|
Oil, natural gas and NGLs (MBoe)
|
5,841
|
|
|
|
2,156
|
|
|
13,398
|
|
|
14,468
|
|
|
Average sales prices:
(1)
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
50.80
|
|
|
|
$
|
50.48
|
|
|
$
|
44.59
|
|
|
$
|
69.52
|
|
|
Natural gas (per Mcf)
|
2.48
|
|
|
|
2.68
|
|
|
2.19
|
|
|
2.29
|
|
|
NGLs (per Bbl)
|
23.85
|
|
|
|
21.34
|
|
|
13.23
|
|
|
13.46
|
|
|
Oil, natural gas and NGLs (per Boe)
|
41.14
|
|
|
|
31.55
|
|
|
27.97
|
|
|
36.79
|
|
|
Expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (2)
|
$
|
8.53
|
|
|
|
$
|
4.09
|
|
|
$
|
5.94
|
|
|
$
|
6.92
|
|
|
Transportation, processing and gathering expenses
|
0.70
|
|
|
|
3.22
|
|
|
2.07
|
|
|
4.07
|
|
|
|
|
|
(1)
|
Prices for the years ended December 31, 2016 and 2015 include the realized impact of derivative instrument settlements, which increased the price of oil by $3.77 per Bbl and $22.64 per Bbl, respectively, and increased the price of gas by $0.39 per Mcf for each of the years ended December 31, 2016 and 2015.
|
|
|
|
|
(2)
|
Includes oil and gas operating costs and major maintenance expense and excludes production taxes.
|
Production Volumes, Sales Price and Cost Data for Individually Significant Fields.
The following tables set forth certain information regarding our oil, natural gas and NGL production volumes, sales prices and average production costs for the periods indicated for any field(s) containing 15% or more of our total estimated proved reserves at
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
FIELD: Pompano (1)
|
|
|
|
2016
|
|
2015
|
|
Production:
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
2,649
|
|
|
|
547
|
|
|
3,858
|
|
|
2,994
|
|
|
Natural gas (MMcf)
|
3,531
|
|
|
|
689
|
|
|
7,882
|
|
|
3,466
|
|
|
NGLs (MBbls)
|
267
|
|
|
|
44
|
|
|
267
|
|
|
245
|
|
|
Oil, natural gas and NGLs (MBoe)
|
3,505
|
|
|
|
706
|
|
|
5,439
|
|
|
3,817
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
51.60
|
|
|
|
$
|
52.11
|
|
|
$
|
41.86
|
|
|
$
|
49.18
|
|
|
Natural gas (per Mcf)
|
2.47
|
|
|
|
2.46
|
|
|
2.15
|
|
|
2.17
|
|
|
NGLs (per Bbl)
|
22.24
|
|
|
|
24.60
|
|
|
12.46
|
|
|
15.28
|
|
|
Oil, natural gas and NGLs (per Boe)
|
43.18
|
|
|
|
44.33
|
|
|
33.43
|
|
|
41.53
|
|
|
Expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (2)
|
$
|
4.48
|
|
|
|
$
|
2.31
|
|
|
$
|
4.69
|
|
|
$
|
5.47
|
|
|
Transportation, processing and gathering expenses
|
0.37
|
|
|
|
0.49
|
|
|
0.58
|
|
|
0.44
|
|
|
|
|
|
(1)
|
Includes the Pompano and Cardona fields, both of which tie back to the Pompano platform. Amounts for 2015 and 2016 include production and expenses for the Amethyst well which also tied back to the Pompano platform. The Amethyst well was shut-in in April 2016, and the lease was ultimately surrendered during the second quarter of 2017.
|
|
|
|
|
(2)
|
Includes oil and gas operating costs and major maintenance expense and excludes production taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
FIELD: Mississippi Canyon Block 109
|
|
|
|
2016
|
|
2015
|
|
Production:
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
665
|
|
|
|
143
|
|
|
861
|
|
|
861
|
|
|
Natural gas (MMcf)
|
809
|
|
|
|
175
|
|
|
1,087
|
|
|
1,267
|
|
|
NGLs (MBbls)
|
19
|
|
|
|
4
|
|
|
22
|
|
|
42
|
|
|
Oil, natural gas and NGLs (MBoe)
|
819
|
|
|
|
176
|
|
|
1,064
|
|
|
1,114
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
49.18
|
|
|
|
$
|
49.21
|
|
|
$
|
39.22
|
|
|
$
|
47.75
|
|
|
Natural gas (per Mcf)
|
1.37
|
|
|
|
1.51
|
|
|
1.20
|
|
|
1.41
|
|
|
NGLs (per Bbl)
|
30.88
|
|
|
|
32.33
|
|
|
23.79
|
|
|
24.78
|
|
|
Oil, natural gas and NGLs (per Boe)
|
42.00
|
|
|
|
42.23
|
|
|
33.47
|
|
|
39.43
|
|
|
Expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (1)
|
$
|
13.36
|
|
|
|
$
|
9.43
|
|
|
$
|
9.94
|
|
|
$
|
9.94
|
|
|
Transportation, processing and gathering expenses (2)
|
0.27
|
|
|
|
1.81
|
|
|
(2.62
|
)
|
|
0.32
|
|
|
|
|
|
(1)
|
Includes oil and gas operating costs and major maintenance expense and excludes production taxes.
|
|
|
|
|
(2)
|
The year ended December 31, 2016 includes the recoupment of prior period expenses against federal royalties.
|
Drilling Activity.
The following table sets forth our drilling activity for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
1
|
|
|
0.40
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.25
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.42
|
|
|
Development Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
—
|
|
|
—
|
|
|
1
|
|
|
0.65
|
|
|
7
|
|
|
5.81
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
During the period from January 1, 2018 through
March 9, 2018
, we drilled one successful development well in which we own a 100% working interest.
Productive Well and Acreage Data.
The following table sets forth certain statistics regarding the number of productive wells as of
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
Net
|
|
Productive Wells:
|
|
|
|
|
Oil (1):
|
|
|
|
|
Deep Water
|
48
|
|
|
43
|
|
|
Deep Gas
|
—
|
|
|
—
|
|
|
Conventional Shelf
|
28
|
|
|
28
|
|
|
|
76
|
|
|
71
|
|
|
Gas:
|
|
|
|
|
Deep Water
|
2
|
|
|
2
|
|
|
Deep Gas
|
2
|
|
|
1
|
|
|
Conventional Shelf
|
6
|
|
|
5
|
|
|
|
10
|
|
|
8
|
|
|
Total productive wells
|
86
|
|
|
79
|
|
(1) Five gross wells each have dual completions.
The following table sets forth certain statistics regarding developed and undeveloped acres as of
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
Net
|
|
Developed Acres:
|
|
|
|
|
Deep Water
|
86,400
|
|
|
50,891
|
|
|
Deep Gas
|
23,797
|
|
|
1,576
|
|
|
Conventional Shelf
|
67,789
|
|
|
47,029
|
|
|
Other
|
6,427
|
|
|
2,250
|
|
|
|
184,413
|
|
|
101,746
|
|
|
Undeveloped Acres:
|
|
|
|
|
Deep Water
|
201,600
|
|
|
118,376
|
|
|
Deep Gas
|
7,971
|
|
|
3,884
|
|
|
Conventional Shelf
|
—
|
|
|
—
|
|
|
Other
|
160
|
|
|
160
|
|
|
|
209,731
|
|
|
122,420
|
|
|
Total developed and undeveloped acres
|
394,144
|
|
|
224,166
|
|
Leases covering approximately 16% of our undeveloped gross acreage will expire in
2018
, 25% in
2019
, 14% in
2020
, 9% in
2021
, 14% in
2022
, 16% in
2023
, and 3% in
2024
. As of
December 31, 2017
, none of our PUDs were assigned to locations that are currently scheduled to be drilled after lease expiration.
The acreage statistics above include both producing and non-producing acres. Of the producing acres, 49,788 gross acres (20,280 net) are producing acres of third parties that Stone has deep rights interest in only.
Title to Properties
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and gas industry. Before we commence drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our active properties.
ITEM 3. LEGAL PROCEEDINGS
We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.
On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. Stone emerged from bankruptcy effective February 28, 2017, and the bankruptcy cases were closed by order of the Bankruptcy Court on April 20, 2017.
In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. Stone emerged from bankruptcy effective February 28, 2017, and the bankruptcy cases were closed by order of the Bankruptcy Court on April 20, 2017.
On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern, with the participation of the PADEP and Stone, was completed. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.
On each of January 4, February 2, and February 8, 2018, separate lawsuits were filed against Stone Energy Corporation, the individual directors of the board of directors of Stone Energy Corporation and other named co-defendants by stockholders of Stone Energy Corporation. Two of the lawsuits were filed in the U.S. District Court of Delaware and the third lawsuit was filed in the U.S. District Court for the Western District Louisiana. The three lawsuits allege violations of Sections 14(a), and 20(a) of the Securities Exchange Act of 1934 and SEC Rule 14a-9 on the grounds that the Form S-4 Registration Statement filed on December 29, 2017, was materially incomplete because it omitted material information concerning the transactions contemplated by that certain Transaction Agreement, dated November 21, 2017, by and among Stone Energy Corporation, certain wholly-owned, direct and indirect, subsidiaries of Stone Energy Corporation, Talos Energy LLC and Talos Production LLC. The three lawsuits also seek certification as class actions. These lawsuits were recently filed and are in the preliminary stages of defense and assessment. The defendants believe that the allegations contained in the matters described above are without merit and intend to vigorously defend themselves against the claims raised.
Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Stone Energy Corporation (“Stone” or the “Company”) is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (the “GOM”) Basin since our incorporation in 1993 and have established technical and operational expertise in this area. We leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific plays of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. At December 31, 2016, we had producing properties and acreage in the Marcellus and Utica Shales in Appalachia. In connection with our restructuring efforts, we completed the sale of the Appalachia Properties (as defined in
Note 2 – Reorganization
) to EQT Corporation, through its wholly owned subsidiary EQT Production Company (“EQT”), on February 27, 2017 for net cash consideration of approximately
$522.5 million
. See
Note 2 – Reorganization
and
Note 4 – Divestiture
for additional information on the sale of the Appalachia Properties. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have an additional office in New Orleans, Louisiana.
Pending Combination with Talos
On November 21, 2017, Stone and certain of its subsidiaries entered into a series of related agreements pertaining to a business combination with Talos Energy LLC (“Talos Energy”) and its indirect wholly owned subsidiary Talos Production LLC (“Talos Production” and, together with Talos Energy, “Talos”). Talos Energy is controlled indirectly by entities controlled by Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (together with Apollo VII, “Apollo Management”) and Riverstone Energy Partners V, L.P. (“Riverstone”).
Stone, Sailfish Energy Holdings Corporation (“New Talos”), a direct wholly owned subsidiary of Stone, and Sailfish Merger Sub Corporation, a direct wholly owned subsidiary of New Talos, entered into a Transaction Agreement (the “Transaction Agreement”) with Talos on November 21, 2017, which contemplates a series of transactions (the “Transactions”) occurring on the date of closing of the Transaction Agreement (the “Closing”) that will result in such business combination. Stone and Talos will become wholly owned subsidiaries of New Talos. At the time of the Closing, the parties intend that New Talos will become a publicly traded entity named Talos Energy, Inc. The Transactions include (i) the contribution of
100%
of the equity interests in Talos Production to New Talos in exchange for shares of New Talos common stock, (ii) the contribution by entities controlled by or affiliated with Apollo Management (the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of
$102 million
in aggregate principal amount of
9.75%
Senior Notes due 2022 issued by Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for shares of New Talos common stock, (iii) the exchange of the second lien bridge loans due 2022 issued by the Talos Issuers for newly issued
11%
second lien notes issued by the Talos Issuers, and (iv) the exchange of the
7.50%
Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued
11%
second lien notes issued by the Talos Issuers.
Under the terms of the Transaction Agreement, each outstanding share of Stone common stock will be exchanged for
one
share of New Talos common stock and the current Talos stakeholders (including the Apollo Funds and the Riverstone Funds) will be issued an aggregate of approximately
34.1 million
common shares of New Talos. After the completion of the Transactions contemplated by the Transaction Agreement, holders of Stone common stock immediately prior to the combination will collectively hold
37%
of the outstanding New Talos common stock and Talos Energy stakeholders will hold
63%
of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions.
The combination was unanimously approved by the boards of directors of Stone and Talos Energy. Completion of the combination is subject to the approval of Stone shareholders, the consummation of a tender offer and consent solicitation for Stone’s 2022 Second Lien Notes, certain regulatory approvals and other customary conditions. Franklin Advisers, Inc. and MacKay Shields LLC, as investment managers for approximately
53%
of the outstanding common shares of Stone as of September 30, 2017, entered into voting agreements to vote in favor of the combination, subject to certain conditions. The Transaction Agreement contains certain termination rights for Stone and Talos Energy. Stone may be required to pay a termination fee and to reimburse transaction expenses to Talos Energy if the Transaction Agreement is terminated under certain circumstances. The combination is expected to close in the second quarter of 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all.
Reorganization and Emergence from Voluntary Chapter 11 Proceedings
On December 14, 2016 (the “Petition Date”), the Company and its subsidiaries Stone Energy Offshore, L.L.C. (“Stone Offshore”) and Stone Energy Holding, L.L.C. (together with the Company, the “Debtors”)
filed voluntary petitions (the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). On February 15, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the “Plan”), as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017. See
Note 2 – Reorganization
for additional details.
Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “
Reorganizations
”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. See
Note 3 – Fresh Start Accounting
for further details on the impact of fresh start accounting on the Company’s consolidated financial statements.
References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.
Summary of Significant Accounting Policies
A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.
Basis of Presentation:
The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.
Reorganization and Fresh Start Accounting:
For periods subsequent to the Chapter 11 filing, but prior to emergence, ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations for the applicable periods. In addition, pre-petition obligations that were to be impacted by the Chapter 11 process were classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. See
Note 2 – Reorganization
and
Note 3 – Fresh Start Accounting
for more information regarding reorganization items and liabilities subject to compromise.
Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. The new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.
The Chapter 11 proceedings did not include our former foreign subsidiary Stone Energy Canada, ULC. This subsidiary had no significant activity during 2016, except for the reclassification of approximately
$6.1 million
of losses related to cumulative
foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of Stone Energy Canada, ULC. Stone Energy Canada, ULC was dissolved on December 2, 2016.
Use of Estimates:
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and on various assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are uncertain and, accordingly, these estimates may change as new events occur, as additional information is obtained and as the Company’s operating environment changes. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, estimated fair value of derivative contracts, contingencies and fair value estimates, including estimates of reorganization value, enterprise value and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.
Fair Value Measurements:
U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of
December 31, 2017
and
2016
, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.
On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. See
Note 3 – Fresh Start Accounting
for a detailed discussion of the fair value approaches used by the Company.
Cash and Cash Equivalents:
We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents. On December 31, 2017, we had
$18.7 million
of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Agreement (as defined in
Note 13 – Debt
).
Oil and Gas Properties:
We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.
U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. Under the full cost method, all exploratory costs are capitalized, while under the successful efforts method, exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries, while under the successful efforts method, cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.
We amortize our investment in oil and gas properties through DD&A expense using the units of production (the “UOP”) method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.
Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows.
Sales of oil and gas properties are accounted for as adjustments to net oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Asset Retirement Obligations:
U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, timing of abandonment and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.
Other Property and Equipment:
Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful lives of
39
years.
Derivative Instruments and Hedging Activities:
Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, the contracts were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts are recorded in earnings through derivative income (expense).
Earnings Per Common Share:
Under U.S. GAAP, certain instruments granted in share-based payment transactions are considered participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.
Production Revenue:
We recognize production revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered or underdelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. See
Recently Issued Accounting Standards
below.
Income Taxes:
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment costs relative to successful wells are capitalized and recovered through DD&A, although for
2015
,
2016
and
2017
, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to
expense as incurred; however, we follow certain provisions of the Internal Revenue Code (the “IRC”) that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation. See
Note 12 – Income Taxes
for a discussion of the effects of the December 22, 2017 enactment of the Tax Cuts and Jobs Act.
Share-Based Compensation:
We record share-based compensation using the grant date fair value of issued stock options, stock awards, restricted stock and restricted stock units over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of stock awards, restricted stock and restricted stock units is typically determined based on the average of our high and low stock prices on the grant date.
Combination Transaction Costs:
In general, acquisition-related costs are expensed in the periods in which the costs are incurred and the services are rendered. However, some direct costs of an acquisition, such as the cost of registering and issuing equity securities to effect a business combination, are recorded as a reduction of additional paid-in-capital when incurred.
Recently Issued Accounting Standards:
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “
Revenue from Contracts with Customers (Topic 606)
” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including the disaggregation of revenue and remaining performance obligations. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application, and is effective for interim and annual periods beginning on or after December 15, 2017.
We adopted this new standard on January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues.
In February 2016, the FASB issued ASU 2016-02, “
Leases (Topic 842)
” to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public companies for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, “
Compensation – Stock Compensation (Topic 718)
” to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective for us on January 1, 2017. Under ASU 2016-09, we elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. The implementation of this new standard did not have a material effect on our financial statements or related disclosures.
In August 2017, the FASB issued ASU 2017-12, “
Derivatives and Hedging (Topic 815)
” to improve the financial reporting of hedging relationships to better reflect an entity’s hedging strategies. The standard expands an entity’s ability to apply hedge accounting for both non-financial and financial risk components and amends the presentation and disclosure requirements. Additionally, ASU 2017-12 eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be recorded in the same income statement line as the earnings effect of the hedged item. The standard is effective for public companies for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The standard must be adopted by applying a modified retrospective approach to existing designated hedging relationships as of the adoption date, with a cumulative effect adjustment recorded to opening retained earnings as of the initial adoption date. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.
NOTE 2 — REORGANIZATION
On December 14, 2016, the Debtors filed the Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy.
Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors and certain holders of the Company’s 1¾% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) and the Company’s 7
1
⁄
2
% Senior Notes due 2022 (the “2022 Notes”) (collectively, the “Notes” and the holders thereof, the “Noteholders”) and the lenders (the “Banks”) under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the “Pre-Emergence Credit Agreement”), entered into an Amended and Restated Restructuring Support Agreement (the “A&R RSA”). The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the Company’s sale of Stone’s producing properties and acreage, including approximately
86,000
net acres, in the Appalachia regions of Pennsylvania and West Virginia (the “Appalachia Properties”) to TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”), pursuant to the terms of a Purchase and Sale Agreement dated October 20, 2016, as amended on December 9, 2016 (the “Tug Hill PSA”) for a purchase price of at least
$350 million
and approval of the Bankruptcy Court.
Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for
$360 million
in cash, subject to customary purchase price adjustments.
Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017,
two
additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. On January 18, 2017, the Bankruptcy Court approved certain bidding procedures (the “Bidding Procedures”) in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT, with a final purchase price of
$527 million
in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to
$16 million
in an amount equal to certain downward adjustments, as the prevailing bid. On February 9, 2017, the Company entered into a purchase and sale agreement with EQT (the “EQT PSA”), reflecting the terms of the prevailing bid and on February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We completed the sale of the Appalachia Properties to EQT on February 27, 2017 for net cash consideration of approximately
$522.5 million
. At the close of the sale of the Appalachia Properties, the Tug Hill PSA was terminated, and the Company used a portion of the cash consideration received to pay Tug Hill a break-up fee and expense reimbursements totaling approximately
$11.5 million
, which is recognized as other expense in the statement of operations for the period of January 1, 2017 through February 28, 2017 (Predecessor). See
Note 4 – Divestiture
for additional information on the sale of the Appalachia Properties.
Upon emergence from bankruptcy, pursuant to the terms of the Plan, the following significant transactions occurred:
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Shares of the Predecessor Company’s issued and outstanding common stock immediately prior to the Effective Date were cancelled, and on the Effective Date, reorganized Stone issued an aggregate of
20.0 million
shares of new common stock (the “New Common Stock”).
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The Predecessor Company’s 2022 Notes and 2017 Convertible Notes were cancelled and the holders of such notes received their pro rata share of (a) $
100
million of cash, (b)
19.0 million
shares of New Common Stock, representing
95%
of the New Common Stock and (c) $
225
million of the 2022 Second Lien Notes.
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The Predecessor Company’s common stockholders received their pro rata share of
1.0 million
shares of the New Common Stock, representing
5%
of the New Common Stock, and warrants to purchase approximately
3.5 million
shares of New Common Stock. The warrants have an exercise price of
$42.04
per share and a term of
four years
, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.
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The Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement (as defined in
Note 13 – Debt
). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement.
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All claims of creditors with unsecured claims, other than claims by the holders of the 2022 Notes and 2017 Convertible Notes, including vendors, were unaltered and paid in full in the ordinary course of business to the extent such claims were undisputed.
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For further information regarding the equity and debt instruments of the Predecessor Company and the Successor Company, see
Note 5 – Stockholders’ Equity
and
Note 13 – Debt
.
NOTE 3 — FRESH START ACCOUNTING
Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, “
Reorganizations
” as (i) the holders of existing voting shares of the Predecessor Company received less than
50%
of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. See
Note 2 – Reorganization
for the terms of the Plan. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with
no
beginning retained earnings or deficit as of the fresh start reporting date. As described in
Note 1 – Organization and Summary of Significant Accounting Policies
, the new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.
Reorganization Value
Under fresh start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Upon application of fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.
The Company’s reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt and stockholders’ equity. In support of the Plan, the Company estimated the enterprise value of the core assets (as defined in the Plan) of the Successor Company to be in the range of
$300 million
to
$450 million
, which was subsequently approved by the Bankruptcy Court. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses. Based on the estimates and assumptions used in determining the enterprise value, the Company ultimately estimated the enterprise value of the Successor Company’s core assets to be approximately
$420 million
.
Valuation of Assets
The Company’s principal assets are its oil and gas properties, which the Company accounts for under the full cost accounting method. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.
The fair value analysis performed by valuation experts was based on the Company’s estimates of reserves as developed internally by the Company’s reserve engineers. For purposes of estimating the fair value of the Company’s proved, probable and possible reserves, an income approach was used, which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital of
12.5%
. The discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar market participants.
Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company, and adjusted for a
2%
annual escalation after 2021. Development and operating costs were based on the Company’s recent cost trends adjusted for inflation. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses. The proved reserve locations were limited to wells expected to be drilled in the Company’s
five
year development plan.
As a result of this analysis, the Company concluded the fair value of its proved reserves was
$380.8 million
and the fair value of its probable and possible reserves was
$16.8 million
as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and inventory. An analysis of comparable market transactions indicated a fair value of undeveloped acreage and inventory totaling
$80.2 million
. These amounts are reflected in the
Fresh Start Adjustments
item number 12 below. The fair value of the Company’s asset retirement obligations was estimated at
$290.1 million
and was based on estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate of
12%
.
See further discussion in
Fresh Start Adjustments
below for details on the specific assumptions used in the valuation of the Company’s various other assets.
The following table reconciles the enterprise value per the Plan to the estimated fair value (for fresh start accounting purposes) of the Successor Company’s common stock as of February 28, 2017 (in thousands, except per share value):
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February 28, 2017
|
|
Enterprise value
|
|
$
|
419,720
|
|
|
Plus: Cash and other assets
|
|
371,278
|
|
|
Less: Fair value of debt
|
|
(236,261
|
)
|
|
Less: Fair value of warrants
|
|
(15,648
|
)
|
|
Fair value of Successor common stock
|
|
$
|
539,089
|
|
|
|
|
|
|
Shares issued upon emergence
|
|
20,000
|
|
|
Per share value
|
|
$
|
26.95
|
|
The following table reconciles the enterprise value per the Plan to the estimated reorganization value as of the Effective Date (in thousands):
|
|
|
|
|
|
|
|
|
|
|
February 28, 2017
|
|
Enterprise value
|
|
$
|
419,720
|
|
|
Plus: Cash and other assets
|
|
371,278
|
|
|
Plus: Asset retirement obligations (current and long-term)
|
|
290,067
|
|
|
Plus: Working capital and other liabilities
|
|
58,055
|
|
|
Reorganization value of Successor assets
|
|
$
|
1,139,120
|
|
Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.
Condensed Consolidated Balance Sheet
The adjustments set forth in the following condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs. The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
198,571
|
|
|
$
|
(35,605
|
)
|
(1)
|
$
|
—
|
|
|
$
|
162,966
|
|
|
Restricted cash
|
—
|
|
|
75,547
|
|
(1)
|
—
|
|
|
75,547
|
|
|
Accounts receivable
|
42,808
|
|
|
9,301
|
|
(2)
|
—
|
|
|
52,109
|
|
|
Fair value of derivative contracts
|
1,267
|
|
|
—
|
|
|
—
|
|
|
1,267
|
|
|
Current income tax receivable
|
22,516
|
|
|
—
|
|
|
—
|
|
|
22,516
|
|
|
Other current assets
|
11,033
|
|
|
875
|
|
(3)
|
(124
|
)
|
(12)
|
11,784
|
|
|
Total current assets
|
276,195
|
|
|
50,118
|
|
|
(124
|
)
|
|
326,189
|
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
|
|
|
|
Proved
|
9,633,907
|
|
|
(188,933
|
)
|
(1)
|
(8,774,122
|
)
|
(12)
|
670,852
|
|
|
Less: accumulated DD&A
|
(9,215,679
|
)
|
|
—
|
|
|
9,215,679
|
|
(12)
|
—
|
|
|
Net proved oil and gas properties
|
418,228
|
|
|
(188,933
|
)
|
|
441,557
|
|
|
670,852
|
|
|
Unevaluated
|
371,140
|
|
|
(127,838
|
)
|
(1)
|
(146,292
|
)
|
(12)
|
97,010
|
|
|
Other property and equipment, net
|
25,586
|
|
|
(101
|
)
|
(4)
|
(4,423
|
)
|
(13)
|
21,062
|
|
|
Fair value of derivative contracts
|
1,819
|
|
|
—
|
|
|
—
|
|
|
1,819
|
|
|
Other assets, net
|
26,516
|
|
|
(4,328
|
)
|
(5)
|
—
|
|
|
22,188
|
|
|
Total assets
|
$
|
1,119,484
|
|
|
$
|
(271,082
|
)
|
|
$
|
290,718
|
|
|
$
|
1,139,120
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable to vendors
|
$
|
20,512
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20,512
|
|
|
Undistributed oil and gas proceeds
|
5,917
|
|
|
(4,139
|
)
|
(1)
|
—
|
|
|
1,778
|
|
|
Accrued interest
|
266
|
|
|
—
|
|
|
—
|
|
|
266
|
|
|
Asset retirement obligations
|
92,597
|
|
|
—
|
|
|
—
|
|
|
92,597
|
|
|
Fair value of derivative contracts
|
476
|
|
|
—
|
|
|
—
|
|
|
476
|
|
|
Current portion of long-term debt
|
411
|
|
|
—
|
|
|
—
|
|
|
411
|
|
|
Other current liabilities
|
17,032
|
|
|
(195
|
)
|
(6)
|
—
|
|
|
16,837
|
|
|
Total current liabilities
|
137,211
|
|
|
(4,334
|
)
|
|
—
|
|
|
132,877
|
|
|
Long-term debt
|
352,350
|
|
|
(116,500
|
)
|
(7)
|
—
|
|
|
235,850
|
|
|
Asset retirement obligations
|
151,228
|
|
|
(8,672
|
)
|
(1)
|
54,914
|
|
(14)
|
197,470
|
|
|
Fair value of derivative contracts
|
653
|
|
|
—
|
|
|
—
|
|
|
653
|
|
|
Other long-term liabilities
|
17,533
|
|
|
—
|
|
|
—
|
|
|
17,533
|
|
|
Total liabilities not subject to compromise
|
658,975
|
|
|
(129,506
|
)
|
|
54,914
|
|
|
584,383
|
|
|
Liabilities subject to compromise
|
1,110,182
|
|
|
(1,110,182
|
)
|
(8)
|
—
|
|
|
—
|
|
|
Total liabilities
|
1,769,157
|
|
|
(1,239,688
|
)
|
|
54,914
|
|
|
584,383
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
Common stock (Predecessor)
|
56
|
|
|
(56
|
)
|
(9)
|
—
|
|
|
—
|
|
|
Treasury stock (Predecessor)
|
(860
|
)
|
|
860
|
|
(9)
|
—
|
|
|
—
|
|
|
Additional paid-in capital (Predecessor)
|
1,660,810
|
|
|
(1,660,810
|
)
|
(9)
|
—
|
|
|
—
|
|
|
Common stock (Successor)
|
—
|
|
|
200
|
|
(10)
|
—
|
|
|
200
|
|
|
Additional paid-in capital (Successor)
|
—
|
|
|
554,537
|
|
(10)
|
—
|
|
|
554,537
|
|
|
Accumulated deficit
|
(2,309,679
|
)
|
|
2,073,875
|
|
(11)
|
235,804
|
|
(15)
|
—
|
|
|
Total stockholders’ equity
|
(649,673
|
)
|
|
968,606
|
|
|
235,804
|
|
|
554,737
|
|
|
Total liabilities and stockholders’ equity
|
$
|
1,119,484
|
|
|
$
|
(271,082
|
)
|
|
$
|
290,718
|
|
|
$
|
1,139,120
|
|
Reorganization Adjustments
|
|
|
|
1.
|
Reflects the net cash proceeds received from the sale of the Appalachia Properties in connection with the Plan and net cash payments made as of the Effective Date from implementation of the Plan (in thousands):
|
|
|
|
|
|
|
|
|
|
Sources:
|
|
|
|
Net cash proceeds from sale of Appalachia Properties (a)
|
|
$
|
512,472
|
|
|
Total sources
|
|
512,472
|
|
|
Uses:
|
|
|
|
Cash transferred to restricted account (b)
|
|
75,547
|
|
|
Break-up fee to Tug Hill
|
|
10,800
|
|
|
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement
|
|
341,500
|
|
|
Repayment of 2017 Convertible Notes and 2022 Notes
|
|
100,000
|
|
|
Other fees and expenses (c)
|
|
20,230
|
|
|
Total uses
|
|
548,077
|
|
|
Net uses
|
|
$
|
(35,605
|
)
|
(a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. See
Note 4 – Divestiture
for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of
$522.5 million
included cash consideration of
$512.5 million
received at closing and a
$10.0 million
indemnity escrow which was released subsequent to emergence from bankruptcy (see
Reorganization Adjustments
item number 2 below).
(b) Reflects the movement of
$75.0 million
of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined in
Note 13 – Debt
), and
$0.5 million
held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings.
|
|
|
|
(c)
|
Other fees and expenses include approximately
$15.2 million
of emergence and success fees,
$2.7 million
of professional fees and
$2.4 million
of payments made to seismic providers in settlement of their bankruptcy claims.
|
|
|
|
|
2.
|
Reflects a receivable for a
$10.0 million
indemnity escrow with release delayed until emergence from bankruptcy, net of a
$0.7 million
reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (see
Note 4 – Divestiture
).
|
|
|
|
|
3.
|
Reflects the payment of a claim to a seismic provider as a prepayment/deposit.
|
|
|
|
|
4.
|
Reflects the sale of vehicles in connection with the sale of the Appalachia Properties.
|
|
|
|
|
5.
|
Reflects the write-off of
$2.6 million
of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a
$1.8 million
prepayment made to Tug Hill in October 2016.
|
|
|
|
|
6.
|
Reflects the accrual of
$2.0 million
in expected bonus payments under the KEIP (as defined in
Note 15 –
Employee Benefit Plans
) and a
$0.4 million
termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of
$2.6 million
in connection with the sale of the Appalachia Properties.
|
|
|
|
|
7.
|
Reflects the repayment of
$341.5 million
of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of
$225 million
of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes.
|
|
|
|
|
8.
|
Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):
|
|
|
|
|
|
|
|
|
|
1 ¾% Senior Convertible Notes due 2017
|
|
$
|
300,000
|
|
|
7 ½% Senior Notes due 2022
|
|
775,000
|
|
|
Accrued interest
|
|
35,182
|
|
|
Liabilities subject to compromise of the Predecessor Company
|
|
1,110,182
|
|
|
Cash payment to senior noteholders
|
|
(100,000
|
)
|
|
Issuance of 2022 Second Lien Notes to former holders of the senior notes
|
|
(225,000
|
)
|
|
Fair value of equity issued to unsecured creditors
|
|
(539,089
|
)
|
|
Fair value of warrants issued to unsecured creditors
|
|
(15,648
|
)
|
|
Gain on settlement of liabilities subject to compromise
|
|
$
|
230,445
|
|
|
|
|
|
9.
|
Reflects the cancellation of the Predecessor Company’s common stock, treasury stock and additional paid-in capital.
|
|
|
|
|
10.
|
Reflects the issuance of Successor Company equity. In accordance with the Plan, the Successor Company issued
19.0 million
shares of New Common Stock to the former holders of the 2017 Convertible Notes and the 2022 Notes and
1.0 million
shares of New Common Stock to the Predecessor Company’s common stockholders. These amounts are subject to dilution by warrants issued to the Predecessor Company common stockholders, totaling approximately
3.5 million
shares, with an exercise price of
$42.04
per share and a term of
four
years. The fair value of the warrants was estimated at
$4.43
per share using a Black-Scholes-Merton valuation model.
|
11.
Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):
|
|
|
|
|
|
|
|
|
Gain on settlement of liabilities subject to compromise
|
|
$
|
230,445
|
|
|
Professional and other fees paid at emergence
|
|
(10,648
|
)
|
|
Write-off of unamortized debt issuance costs
|
|
(2,577
|
)
|
|
Other reorganization adjustments
|
|
(1,915
|
)
|
|
Net impact to reorganization items
|
|
215,305
|
|
|
Gain on sale of Appalachia Properties
|
|
213,453
|
|
|
Cancellation of Predecessor Company equity
|
|
1,662,282
|
|
|
Other adjustments to accumulated deficit
|
|
(17,165
|
)
|
|
Net impact to accumulated deficit
|
|
$
|
2,073,875
|
|
Fresh Start Adjustments
|
|
|
|
12.
|
Fair value adjustments to oil and gas properties, associated inventory and unproved acreage. See above for a detailed discussion of the fair value methodology.
|
|
|
|
|
13.
|
Fair value adjustment for an office building owned by the Company. The income and sales comparison approaches were used in determining the fair value, using anticipated future earnings and an appropriate expected rate of return, as well as relying upon recent sales or offerings of similar assets.
|
|
|
|
|
14.
|
Fair value adjustments to the Company’s asset retirement obligations using estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate.
|
|
|
|
|
15.
|
Reflects the cumulative effect of the fresh start accounting adjustments discussed above.
|
Reorganization Items
Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “Reorganization items, net” in the Company’s consolidated statement of operations. The following table summarizes reorganization items, net (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Gain on settlement of liabilities subject to compromise
|
|
|
|
$
|
230,445
|
|
|
Fresh start valuation adjustments
|
|
|
|
235,804
|
|
|
Reorganization professional fees and other expenses
|
|
|
|
(20,403
|
)
|
|
Write-off of unamortized debt issuance costs
|
|
|
|
(2,577
|
)
|
|
Other reorganization items
|
|
|
|
(5,525
|
)
|
|
Gain on reorganization items, net
|
|
|
|
$
|
437,744
|
|
The cash payments for reorganization items for the period from January 1, 2017 through February 28, 2017 include approximately
$10.6 million
of emergence and success fees and approximately
$8.9 million
of other reorganization professional fees and expenses paid on the Effective Date.
NOTE 4 — DIVESTITURE
On February 27, 2017, we completed the sale of the Appalachia Properties to EQT for net cash consideration of approximately
$522.5 million
, representing gross proceeds of
$527.0 million
adjusted downward by approximately
$4.5 million
for purchase price adjustments for operations related to the Appalachia Properties after June 1, 2016, the effective date of the transaction. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan. See
Note 2 – Reorganization
.
At December 31, 2016, the estimated proved oil and natural gas reserves associated with these assets totaled
18
MMBoe (million barrels of oil equivalent), which represented approximately
34%
of the Predecessor Company’s total estimated proved oil and natural gas reserves, on a volume equivalent basis. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of the capitalized costs of oil and gas properties would have significantly altered the relationship between capitalized costs and proved reserves, we recognized a gain on the sale of
$213.5 million
during the period from January 1, 2017 through February 28, 2017 (Predecessor). The gain on the sale of the Appalachia Properties is computed as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Net consideration received for sale of Appalachia Properties
|
|
$
|
522,472
|
|
|
Add:
|
Release of funds held in suspense
|
|
4,139
|
|
|
|
Transfer of asset retirement obligations
|
|
8,672
|
|
|
|
Other adjustments, net
|
|
2,597
|
|
|
Less:
|
Transaction costs
|
|
(7,087
|
)
|
|
|
Carrying value of properties sold
|
|
(317,340
|
)
|
|
Gain on sale
|
|
$
|
213,453
|
|
The carrying value of the properties sold was determined by allocating total capitalized costs within the U.S. full cost pool between properties sold and properties retained based on their relative fair values.
NOTE 5 — STOCKHOLDERS’ EQUITY
Common Stock
As discussed in
Note 2 – Reorganization
, upon emergence from bankruptcy, all existing shares of Predecessor common stock were cancelled, and the Successor Company issued an aggregate of
20.0 million
shares of New Common Stock, par value
$0.01
per share, to the Predecessor Company’s existing common stockholders and holders of the 2017 Convertible Notes and the 2022 Notes pursuant to the Plan.
Warrants
As discussed in
Note 2 – Reorganization
, the Predecessor Company’s existing common stockholders received warrants to purchase approximately
3.5 million
shares of New Common Stock. The warrants have an exercise price of
$42.04
per share and a term of
four
years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. The Company allocated
$15.6 million
of the enterprise value to the warrants which is reflected in “Successor additional paid-in capital” on the audited consolidated balance sheet at December 31, 2017 (Successor).
NOTE 6 — EARNINGS PER SHARE
On February 28, 2017, upon emergence from Chapter 11 bankruptcy, the Company’s Predecessor equity was cancelled and new equity was issued. Additionally, the Predecessor Company’s 2017 Convertible Notes were cancelled. See
Note 2 – Reorganization
and
Note 5 – Stockholders’ Equity
for further details.
The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Income (numerator):
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(247,639
|
)
|
|
|
$
|
630,317
|
|
|
$
|
(590,586
|
)
|
|
$
|
(1,090,915
|
)
|
|
Net income attributable to participating securities
|
—
|
|
|
|
(4,995
|
)
|
|
—
|
|
|
—
|
|
|
Net income (loss) attributable to common stock - basic
|
$
|
(247,639
|
)
|
|
|
$
|
625,322
|
|
|
$
|
(590,586
|
)
|
|
$
|
(1,090,915
|
)
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(247,639
|
)
|
|
|
$
|
630,317
|
|
|
$
|
(590,586
|
)
|
|
$
|
(1,090,915
|
)
|
|
Net income attributable to participating securities
|
—
|
|
|
|
(4,995
|
)
|
|
—
|
|
|
—
|
|
|
Net income (loss) attributable to common stock - diluted
|
$
|
(247,639
|
)
|
|
|
$
|
625,322
|
|
|
$
|
(590,586
|
)
|
|
$
|
(1,090,915
|
)
|
|
Weighted average shares (denominator):
|
|
|
|
|
|
|
|
|
|
Weighted average shares - basic
|
19,997
|
|
|
|
5,634
|
|
|
5,591
|
|
|
5,525
|
|
|
Dilutive effect of stock options
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Dilutive effect of warrants
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Dilutive effect of convertible notes
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Weighted average shares - diluted
|
19,997
|
|
|
|
5,634
|
|
|
5,591
|
|
|
5,525
|
|
|
Basic income (loss) per share
|
$
|
(12.38
|
)
|
|
|
$
|
110.99
|
|
|
$
|
(105.63
|
)
|
|
$
|
(197.45
|
)
|
|
Diluted income (loss) per share
|
$
|
(12.38
|
)
|
|
|
$
|
110.99
|
|
|
$
|
(105.63
|
)
|
|
$
|
(197.45
|
)
|
All outstanding stock options were considered antidilutive during the period from January 1, 2017 through February 28, 2017 (Predecessor) (
10,400
shares) because the exercise price of the options exceeded the average price of our common stock for the applicable period. During the years ended
December 31, 2016
(Predecessor) (
12,900
shares) and
December 31, 2015
(Predecessor) (
14,400
shares) all outstanding stock options were considered antidilutive because we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled. See
Note 16 – Share-Based Compensation
.
On February 28, 2017, upon emergence from bankruptcy, the Predecessor Company’s existing common stockholders received warrants to purchase common stock of the Successor Company. See
Note 2 – Reorganization
. For the period of March 1, 2017 through December 31, 2017 (Successor), all outstanding warrants (approximately
3.5 million
) were considered antidilutive because we had a net loss for such period.
The Predecessor Company had
no
outstanding restricted stock units. The board of directors of the Successor Company (the “Board”) received grants of restricted stock units on March 1, 2017. See
Note 16 – Share-Based Compensation.
For the period
from March 1, 2017 through December 31, 2017 (Successor), all outstanding restricted stock units (
62,137
) were considered antidilutive because we had a net loss for such period.
For the period from January 1, 2017 through February 28, 2017 (Predecessor), the average price of our common stock was less than the effective conversion price for the 2017 Convertible Notes, resulting in
no
dilutive effect on the diluted earnings per share computation for such period. For the years ended
December 31, 2016
and
2015
(Predecessor), the 2017 Convertible Notes had
no
dilutive effect on the diluted earnings per share computation as we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. See
Note 2 – Reorganization
.
During the period from March 1, 2017 through
December 31, 2017
(Successor),
1,195
shares of common stock of the Successor Company were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees. During the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended
December 31, 2016
and
2015
(Predecessor),
47,390
,
79,621
and
41,375
shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and granting of stock awards for employees and nonemployee directors.
NOTE 7 — ACCOUNTS RECEIVABLE
In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
As of December 31,
|
|
|
As of December 31,
|
|
|
2017
|
|
|
2016
|
|
Other co-venturers
|
$
|
2,656
|
|
|
|
$
|
3,532
|
|
|
Trade
|
34,980
|
|
|
|
42,944
|
|
|
Unbilled accounts receivable
|
820
|
|
|
|
591
|
|
|
Other
|
802
|
|
|
|
1,397
|
|
|
Total accounts receivable
|
$
|
39,258
|
|
|
|
$
|
48,464
|
|
NOTE 8 — CONCENTRATIONS
Sales to Major Customers
Our production is sold on month-to-month contracts at prevailing prices. We obtain credit protections, such as parental guarantees, from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our total oil and natural gas revenue during the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Phillips 66 Company
|
74
|
%
|
|
|
56
|
%
|
|
68
|
%
|
|
53
|
%
|
|
Shell Trading (US) Company
|
15
|
%
|
|
|
7
|
%
|
|
10
|
%
|
|
13
|
%
|
|
Williams Ohio Valley Midstream LLC
|
—
|
%
|
|
|
12
|
%
|
|
2
|
%
|
|
9
|
%
|
|
Conoco
|
—
|
%
|
|
|
11
|
%
|
|
5
|
%
|
|
2
|
%
|
The maximum amount of credit risk exposure at
December 31, 2017
(Successor) relating to these customers was
$30.5 million
.
We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.
Production and Reserve Volumes – Unaudited
All of our estimated proved reserve volumes at
December 31, 2017
(Successor) and approximately
88%
of our production during
2017
were associated with our GOM deep water, conventional shelf and deep gas properties. We closed the sale of the Appalachia Properties on February 27, 2017 and no longer have assets or operations in Appalachia (see
Note 4 – Divestiture)
.
Cash and Cash Equivalents
A substantial portion of our cash balances are not federally insured.
NOTE 9 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative transactions for trading purposes.
All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective cash flow hedges are reflected in revenue from oil and natural gas production. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities.
Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. A small portion of our cash flow hedges were typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products were not
100%
correlative to changes in the underlying price basis indicative in the derivative contract. We had
no
outstanding derivatives at December 31, 2016. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense).
We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2018 and 2019 oil and natural gas production from the Gulf Coast Basin. All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an “investment grade” credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we typically enter into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At
March 9, 2018
, our derivative instruments were with
four
counterparties, two of which accounted for approximately
64%
of our contracted volumes. Currently, all of our outstanding derivative instruments are with lenders under our current bank credit facility.
Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York Mercantile Exchange (“NYMEX”) prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Settlements for our oil put contracts, oil collar contracts and fixed-price oil swaps are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts and fixed-price natural gas swaps are based on the NYMEX price for the last day of a respective contract month.
The following tables illustrate our derivative positions for calendar years 2018 and 2019 as of
March 9, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Contracts (NYMEX)
|
|
|
|
Oil
|
|
|
|
Daily Volume
|
|
Price
|
|
|
|
(Bbls/d)
|
|
($ per Bbl)
|
|
2018
|
January - December
|
1,000
|
|
|
$
|
54.00
|
|
|
2018
|
January - December
|
1,000
|
|
|
45.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-Price Swaps (NYMEX)
|
|
|
|
Oil
|
|
|
|
Daily Volume
|
|
Swap Price
|
|
|
|
(Bbls/d)
|
|
($ per Bbl)
|
|
2018
|
January - December
|
1,000
|
|
|
$
|
52.50
|
|
|
2018
|
January - December
|
1,000
|
|
|
51.98
|
|
|
2018
|
January - December
|
1,000
|
|
|
53.67
|
|
|
2019
|
January - December
|
1,000
|
|
|
51.00
|
|
|
2019
|
January - December
|
1,000
|
|
|
51.57
|
|
|
2019
|
January - December
|
2,000
|
|
|
56.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar Contracts (NYMEX)
|
|
|
|
Natural Gas
|
|
Oil
|
|
|
|
Daily Volume
(MMBtus/d)
|
|
Floor Price
($ per MMBtu)
|
|
Ceiling Price
($ per MMBtu)
|
|
Daily Volume
(Bbls/d)
|
|
Floor Price
($ per Bbl)
|
|
Ceiling Price
($ per Bbl)
|
|
2018
|
January - December
|
6,000
|
|
|
$
|
2.75
|
|
|
$
|
3.24
|
|
|
1,000
|
|
|
$
|
45.00
|
|
|
$
|
55.35
|
|
Derivatives not designated or not qualifying as hedging instruments
The following table discloses the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at
December 31, 2017
(Successor) (in thousands). We had
no
outstanding hedging instruments at December 31, 2016 (Predecessor).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
|
|
December 31, 2017
|
|
(Successor)
|
|
|
Asset Derivatives
|
|
Liability Derivatives
|
|
Description
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Commodity contracts
|
Current assets: Fair value of
derivative contracts
|
|
$
|
879
|
|
|
Current liabilities: Fair value of derivative contracts
|
|
$
|
8,969
|
|
|
|
Long-term assets: Fair value
of derivative contracts
|
|
—
|
|
|
Long-term liabilities: Fair
value of derivative contracts
|
|
3,085
|
|
|
|
|
|
$
|
879
|
|
|
|
|
$
|
12,054
|
|
Gains or losses related to changes in fair value and cash settlements for derivatives not designated or not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not designated or not qualifying as hedging instruments on the statement of operations for the indicated periods (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in Derivative Income (Expense)
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended
|
|
Description
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
Cash settlements
|
|
$
|
2,161
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17,385
|
|
|
Change in fair value
|
|
(15,549
|
)
|
|
|
(1,778
|
)
|
|
—
|
|
|
(12,146
|
)
|
|
Total gains (losses) on derivatives not designated or not qualifying as hedging instruments
|
|
$
|
(13,388
|
)
|
|
|
$
|
(1,778
|
)
|
|
$
|
—
|
|
|
$
|
5,239
|
|
Derivatives qualifying as hedging instruments
None
of our derivative contracts outstanding as of
December 31, 2017
(Successor) were designated as accounting hedges. We had
no
outstanding derivatives at December 31, 2016 (Predecessor). During 2016 and 2015, we had outstanding derivatives that were designated and qualified as hedging instruments. The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31,
2016
and
2015
(Predecessor) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
|
|
for the Years Ended December 31, 2016 and 2015
|
|
(Predecessor)
|
|
Derivatives in Cash
Flow Hedging
Relationships
|
|
Amount of Gain
(Loss) Recognized
in Other
Comprehensive
Income on
Derivatives
|
|
Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income
into Income
(Effective Portion) (a)
|
|
Gain (Loss) Recognized in Income
on Derivatives
(Ineffective Portion)
|
|
|
|
|
|
Location
|
|
|
|
Location
|
|
|
|
|
|
2016
|
|
|
|
2016
|
|
|
|
2016
|
|
Commodity contracts
|
|
$
|
(1,648
|
)
|
|
Operating revenue -
oil/natural gas production
|
|
$
|
35,457
|
|
|
Derivative income (expense), net
|
|
$
|
(810
|
)
|
|
Total
|
|
$
|
(1,648
|
)
|
|
|
|
$
|
35,457
|
|
|
|
|
$
|
(810
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
2015
|
|
|
|
2015
|
|
Commodity contracts
|
|
$
|
52,630
|
|
|
Operating revenue -
oil/natural gas production
|
|
$
|
149,955
|
|
|
Derivative income (expense), net
|
|
$
|
2,713
|
|
|
Total
|
|
$
|
52,630
|
|
|
|
|
$
|
149,955
|
|
|
|
|
$
|
2,713
|
|
|
|
|
|
(a)
|
For the year ended
December 31, 2016
, effective hedging contracts increased oil revenue by
$23,747
and increased natural gas revenue by
$11,710
. For the year ended
December 31, 2015
, effective hedging contracts increased oil revenue by
$135,617
and increased natural gas revenue by
$14,338
.
|
Offsetting of derivative assets and liabilities
Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following table presents the potential impact of the offset rights associated with our recognized assets and liabilities at December 31, 2017 (Successor) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As Presented Without Netting
|
|
Effects of Netting
|
|
With Effects of Netting
|
|
Current assets: Fair value of derivative contracts
|
|
$
|
879
|
|
|
$
|
(879
|
)
|
|
$
|
—
|
|
|
Long-term assets: Fair value of derivative contracts
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Current liabilities: Fair value of derivative contracts
|
|
(8,969
|
)
|
|
879
|
|
|
(8,090
|
)
|
|
Long-term liabilities: Fair value of derivative contracts
|
|
(3,085
|
)
|
|
—
|
|
|
(3,085
|
)
|
We had
no
outstanding derivative contracts at December 31, 2016 (Predecessor).
NOTE 10 — FAIR VALUE MEASUREMENTS
U.S. GAAP establishes a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.
As of
December 31, 2017
(Successor) and
2016
(Predecessor), we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. The income approach is used in this determination utilizing the third party’s proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts are the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see
Note 9 – Derivative Instruments and Hedging Activities
. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.
The following tables present our assets and liabilities that are measured at fair value on a recurring basis at
December 31, 2017
(Successor) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
|
Successor as of
|
|
|
|
December 31, 2017
|
|
Assets
|
|
Total
|
|
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Marketable securities (Other assets)
|
|
$
|
5,081
|
|
|
$
|
5,081
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Derivative contracts
|
|
879
|
|
|
—
|
|
|
—
|
|
|
879
|
|
|
Total
|
|
$
|
5,960
|
|
|
$
|
5,081
|
|
|
$
|
—
|
|
|
$
|
879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
|
Successor as of
|
|
|
|
December 31, 2017
|
|
Liabilities
|
|
Total
|
|
Quoted Prices in
Active Markets for
Identical Liabilities
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Derivative contracts
|
|
$
|
12,054
|
|
|
$
|
—
|
|
|
$
|
10,110
|
|
|
$
|
1,944
|
|
|
Total
|
|
$
|
12,054
|
|
|
$
|
—
|
|
|
$
|
10,110
|
|
|
$
|
1,944
|
|
We had
no
liabilities measured at fair value on a recurring basis at December 31, 2016. The following table presents our assets that are measured at fair value on a recurring basis at December 31, 2016 (Predecessor) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
|
Predecessor as of
|
|
|
|
December 31, 2016
|
|
Assets
|
|
Total
|
|
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Marketable securities (Other assets)
|
|
$
|
8,746
|
|
|
$
|
8,746
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Total
|
|
$
|
8,746
|
|
|
$
|
8,746
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period from March 1, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging Contracts, net
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Beginning balance
|
|
$
|
3,087
|
|
|
|
$
|
—
|
|
|
Total gains/(losses) (realized or unrealized):
|
|
|
|
|
|
|
Included in earnings
|
|
(5,201
|
)
|
|
|
(649
|
)
|
|
Included in other comprehensive income
|
|
—
|
|
|
|
—
|
|
|
Purchases, sales, issuances and settlements
|
|
1,049
|
|
|
|
3,736
|
|
|
Transfers in and out of Level 3
|
|
—
|
|
|
|
—
|
|
|
Ending balance
|
|
$
|
(1,065
|
)
|
|
|
$
|
3,087
|
|
|
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2017
|
|
$
|
(4,699
|
)
|
|
|
|
The fair value of cash and cash equivalents approximated book value at
December 31, 2017
and
2016
. Upon emergence from bankruptcy on February 28, 2017, the 2017 Convertible Notes and 2022 Notes were cancelled, and the Company issued the 2022 Second Lien Notes. As of December 31, 2016, the fair value of the liability component of the 2017 Convertible Notes was approximately
$293.5 million
. As of December 31, 2016, the fair value of the 2022 Notes was approximately
$465.0 million
. As of December 31, 2017, the fair value of the 2022 Second Lien Notes was approximately
$227.3 million
.
The fair values of the 2022 Notes and the 2022 Second Lien Notes were determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes at inception and at December 31, 2016. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.
On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. See
Note 3 – Fresh Start Accounting
for a detailed discussion of the fair value approaches used by the Company. The inputs utilized in the valuation of our most significant asset, our oil and gas properties, included mostly unobservable inputs, which fall within Level 3 of the fair value hierarchy.
NOTE 11 — ASSET RETIREMENT OBLIGATIONS
Upon emergence from bankruptcy, as discussed in
Note 3 – Fresh Start Accounting
, the Company adopted fresh start accounting which included the adjustment of asset retirement obligations to estimated fair values at February 28, 2017. The following table presents the change in our asset retirement obligations during the indicated periods (in thousands, inclusive of current portion):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Beginning balance
|
|
$
|
290,067
|
|
|
|
$
|
242,019
|
|
|
$
|
225,866
|
|
|
$
|
316,409
|
|
|
Liabilities incurred
|
|
2,280
|
|
|
|
—
|
|
|
2,338
|
|
|
15,933
|
|
|
Liabilities settled
|
|
(81,197
|
)
|
|
|
(3,641
|
)
|
|
(19,630
|
)
|
|
(72,713
|
)
|
|
Divestment of properties
|
|
—
|
|
|
|
(8,672
|
)
|
|
—
|
|
|
(248
|
)
|
|
Accretion expense
|
|
21,151
|
|
|
|
5,447
|
|
|
40,229
|
|
|
25,988
|
|
|
Revision of estimates
|
|
(19,200
|
)
|
|
|
—
|
|
|
(6,784
|
)
|
|
(59,503
|
)
|
|
Fair value fresh start adjustment
|
|
—
|
|
|
|
54,914
|
|
|
—
|
|
|
—
|
|
|
Asset retirement obligations, end of period
|
|
$
|
213,101
|
|
|
|
$
|
290,067
|
|
|
$
|
242,019
|
|
|
$
|
225,866
|
|
NOTE 12 — INCOME TAXES
An analysis of our deferred taxes follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
As of December 31,
|
|
|
As of December 31,
|
|
|
2017
|
|
|
2016
|
|
Tax effect of temporary differences:
|
|
|
|
|
|
Net operating loss carryforwards
|
$
|
66,304
|
|
|
|
$
|
201,557
|
|
|
Oil and gas properties
|
12,035
|
|
|
|
85,772
|
|
|
Asset retirement obligations
|
44,751
|
|
|
|
85,312
|
|
|
Stock compensation
|
278
|
|
|
|
3,294
|
|
|
Derivatives
|
3,110
|
|
|
|
—
|
|
|
Accrued incentive compensation
|
2,269
|
|
|
|
954
|
|
|
Debt issuance costs
|
644
|
|
|
|
7,480
|
|
|
Other
|
1,600
|
|
|
|
441
|
|
|
Total deferred tax assets (liabilities)
|
130,991
|
|
|
|
384,810
|
|
|
Valuation allowance
|
(130,991
|
)
|
|
|
(384,810
|
)
|
|
Net deferred tax assets (liabilities)
|
$
|
—
|
|
|
|
$
|
—
|
|
Upon our emergence from bankruptcy, pursuant to the terms of the Plan, a substantial portion of the Company’s pre-petition debt was extinguished (see
Note 2 – Reorganization
). For tax purposes, absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. After consideration of the market value of the Company’s equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately
$257 million
, which will reduce the value of the Company’s U.S. net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2018. The estimated results of the attribute reduction have been reflected in the Company’s ending balance of deferred tax assets for the year ended December 31, 2017 (Successor). The Successor Company
also has various state net operating loss carryforwards that are subject to reduction as a result of the CODI being excluded from taxable income, however, subsequent to the sale of the Appalachia Properties, our state income tax exposure is not expected to be material.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). Generally effective for tax years 2018 and beyond, the Tax Act makes broad and complex changes to the IRC, including, but not limited to, (i) reducing the U.S. federal corporate tax rate from 35% to 21%; (ii) eliminating the corporate alternative minimum tax (“AMT”) and changing how existing AMT credits are realized; (iii) creating a new limitation on deductible interest expense; and (iv) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017. As of December 31, 2017, we have not completed our accounting for the tax effects of enactment of the Tax Act. However, we have made a reasonable estimate of the effects on our existing deferred tax balances and recognized a provisional amount of
$87.3 million
to remeasure our deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. This amount is included as a component of income tax expense (benefit) from continuing operations and is fully offset by the related adjustment to our valuation allowance. We are still analyzing certain aspects of the Tax Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.
We estimate that we had
($18.3) million
and
$3.6 million
, respectively, of current federal income tax expense (benefit) for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor) we had
($5.7) million
and
($44.1) million
, respectively, of current federal income tax (benefits). There was
no
deferred income tax expense (benefit) recorded for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31,
2016
and
2015
(Predecessor), we recorded a deferred income tax expense (benefit) of
$13.1 million
and
($272.3) million
, respectively. The deferred income tax benefit in 2015 was a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see
Note 22 – Supplemental Information on Oil and Natural Gas Operations – Unaudited
). We had current income tax receivables of
$36.3 million
and
$26.1 million
at
December 31, 2017
(Successor) and
2016
(Predecessor), respectively, both of which related to expected tax refunds from the carryback of net operating losses to previous tax years. We received
$20.6 million
of the tax refund subsequent to December 31, 2017.
For tax reporting purposes, our net operating loss carryforwards totaled approximately
$315.7 million
at
December 31, 2017
(net of the aforementioned CODI reduction). If not utilized, such carryforwards would begin to expire in
2035
and would fully expire in 2036. Additionally, IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. Accordingly, we estimate that approximately
$127 million
of our net operating loss carryforwards will be subject to the annual IRC Section 382 limitation, with the remaining
$189 million
of net operating loss carryforwards being unlimited.
In addition, we had approximately
$1.2 million
in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of December 31, 2017 (Successor), our valuation allowance totaled
$131.0 million
. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.
The following table provides a reconciliation of the statutory federal income tax rate to the Company’s effective income tax rate as a percentage of income before income taxes for the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Income tax expense computed at the statutory federal income tax rate
|
35.0%
|
|
|
35.0%
|
|
35.0%
|
|
35.0%
|
|
Tax Act rate change
|
(32.8)
|
|
|
—
|
|
—
|
|
—
|
|
State taxes
|
(0.7)
|
|
|
0.3
|
|
0.2
|
|
0.6
|
|
Change in valuation allowance
|
5.3
|
|
|
(37.8)
|
|
(35.0)
|
|
(12.8)
|
|
IRC Sec. 162(m) limitation
|
0.4
|
|
|
—
|
|
(0.3)
|
|
(0.1)
|
|
Tax deficits on stock compensation
|
(0.6)
|
|
|
0.6
|
|
(0.7)
|
|
(0.1)
|
|
Reorganization fees
|
0.3
|
|
|
2.5
|
|
(0.3)
|
|
—
|
|
Other
|
—
|
|
|
—
|
|
(0.2)
|
|
(0.1)
|
|
Effective income tax rate
|
6.9%
|
|
|
0.6%
|
|
(1.3)%
|
|
22.5%
|
There were
no
income taxes allocated to accumulated other comprehensive income for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to
($13.1) million
,
($35.7) million
for the years ended
December 31, 2016
and
2015
(Predecessor), respectively.
As of
December 31, 2017
(Successor), we had unrecognized tax benefits of
$491 thousand
. If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
|
|
|
|
Total unrecognized tax benefits, beginning balance
|
$
|
491
|
|
|
|
$
|
491
|
|
|
Increases (decreases) in unrecognized tax benefits as a result of:
|
|
|
|
|
|
Tax positions taken during a prior period
|
—
|
|
|
|
—
|
|
|
Tax positions taken during the current period
|
—
|
|
|
|
—
|
|
|
Settlements with taxing authorities
|
—
|
|
|
|
—
|
|
|
Lapse of applicable statute of limitations
|
—
|
|
|
|
—
|
|
|
Total unrecognized tax benefits, ending balance
|
$
|
491
|
|
|
|
$
|
491
|
|
Our unrecognized tax benefits pertain to a proposed state income tax audit adjustment. We believe that our unrecognized tax benefits may be reduced to
zero
within the next 12 months upon completion and ultimate settlement of the examination.
It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized
$33 thousand
and
$7 thousand
, respectively, of interest expense and
no
penalties related to uncertain tax positions for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). We recognized
$46 thousand
of interest expense and
no
penalties related to uncertain tax positions for the year ended
December 31, 2016
(Predecessor). We recognized
$131 thousand
of interest expense and
no
penalties related to uncertain tax positions for the year ended
December 31, 2015
(Predecessor). The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.
The tax years 2014 through 2017 remain subject to examination by major tax jurisdictions.
NOTE 13 — DEBT
Our debt balances (net of related unamortized discounts and debt issuance costs) as of December 31, 2017 and 2016 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31,
|
|
|
December 31,
|
|
|
2017
|
|
|
2016
|
|
7
1⁄2
% Senior Second Lien Notes due 2022
|
$
|
225,000
|
|
|
|
$
|
—
|
|
|
1
3
⁄
4
% Senior Convertible Notes due 2017
|
—
|
|
|
|
300,000
|
|
|
7
1⁄2
% Senior Notes due 2022
|
—
|
|
|
|
775,000
|
|
|
Predecessor revolving credit facility
|
—
|
|
|
|
341,500
|
|
|
4.20% Building Loan
|
10,927
|
|
|
|
11,284
|
|
|
Total debt
|
$
|
235,927
|
|
|
|
$
|
1,427,784
|
|
|
Less: current portion of long-term debt
|
(425
|
)
|
|
|
(408
|
)
|
|
Less: liabilities subject to compromise
|
—
|
|
|
|
(1,075,000
|
)
|
|
Long-term debt
|
$
|
235,502
|
|
|
|
$
|
352,376
|
|
Reorganization
On December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. The 2017 Convertible Notes and 2022 Notes were impacted by the Chapter 11 process and were classified in the accompanying consolidated balance sheet at December 31, 2016 as liabilities subject to compromise under the provisions of ASC 852, “
Reorganizations
”. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Upon emergence from bankruptcy, pursuant to the terms of the Plan, the Predecessor Company’s 2017 Convertible Notes and 2022 Notes were cancelled, the Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated, and the Company issued the 2022 Second Lien Notes.
Current Portion of Long-Term Debt
As of
December 31, 2017
(Successor), the current portion of long-term debt of
$0.4 million
represented principal payments due within one year on the
4.20%
Building Loan (the “Building Loan”).
Reclassification of Deb
t
The face values of the 2017 Convertible Notes of
$300 million
and the 2022 Notes of
$775 million
were reclassified as liabilities subject to compromise in the accompanying consolidated balance sheet at December 31, 2016 (Predecessor). See
Note 1 – Organization and Summary of Significant Accounting Policies
.
Successor Revolving Credit Facility
On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (as amended from time to time, the “Amended Credit Agreement”), as administrative agent and issuing lender, which amended and replaced the Company’s Pre-Emergence Credit Agreement. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.
The Company’s available borrowings under the Amended Credit Agreement were initially set at
$150 million
until the first borrowing base redetermination in November 2017. On November 8, 2017, the borrowing base under the Amended Credit Agreement was redetermined to
$100 million
. On
December 31, 2017
, the Company had
no
outstanding borrowings and
$12.6 million
of outstanding letters of credit, leaving
$87.4 million
of availability under the Amended Credit Agreement. Interest on loans under the Amended Credit Agreement is calculated using the London Interbank Offering Rate (“LIBOR”) or the base rate, at the election of the Company, plus, in each case, an applicable margin. The applicable margin is determined based on borrowing base utilization and ranges from
2.00%
to
3.00%
per annum for base rate loans and
3.00%
to
4.00%
per annum for LIBOR loans.
The borrowing base under the Amended Credit Agreement is redetermined semi-annually, in May and November, by the lenders, in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have
discretion at any time, but not more than two additional times each in any calendar year, to have the borrowing base redetermined. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of
December 31, 2017
, the Amended Credit Agreement is guaranteed by Stone Offshore. The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets.
The Amended Credit Agreement provides for customary optional and mandatory prepayments, affirmative and negative covenants and events of default, including limitations on the incurrence of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the continuance of certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically due and payable). The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than
2.75
x for the test period ending March 31, 2017,
2.50
x for the test period ending June 30, 2017,
3.00
x for the test period ending September 30, 2017,
2.75
x for the test period ending December 31, 2017,
2.50
x for the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively,
2.75
x for the test period ending March 31, 2019,
3.00
x for the test period ending June 30, 2019,
3.50
x for the test periods ending September 30, 2019 and December 31, 2019, respectively,
3.00
x for the test period ending March 31, 2020,
2.75
x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and
2.50
x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a consolidated interest coverage ratio of not less than
2.75
to 1.00, and (iii) a requirement to maintain minimum liquidity of at least
20%
of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of
December 31, 2017
.
Predecessor Revolving Credit Facility
On
June 24, 2014
, the Predecessor Company entered into the Pre-Emergence Credit Agreement with the lenders party thereto and Bank of America, N.A., as administrative agent and issuing lender, with commitments totaling
$900 million
(subject to borrowing base limitations). The borrowing base under the Pre-Emergence Credit Agreement prior to its amendment and restatement as the Amended Credit Agreement was
$150 million
. Interest on loans under the Pre-Emergence Credit Agreement was calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate was determined based on borrowing base utilization and ranged from
1.500%
to
2.500%
.
Prior to emergence from bankruptcy, the Predecessor Company had
$341.5 million
of outstanding borrowings and
$12.5 million
of outstanding letters of credit under the Pre-Emergence Credit Agreement. At emergence, the outstanding borrowings were paid in full and the
$12.5 million
of outstanding letters of credit were converted to obligations under the Amended Credit Agreement.
Building Loan
On November 20, 2015, we entered into an approximately
$11.8 million
term loan agreement, the Building Loan, maturing on November 20, 2030. There were no changes to the terms of the Building Loan pursuant to the Plan. The Building Loan bears interest at a rate of
4.20%
per annum and is to be repaid in
180
equal monthly installments of approximately
$73,000
commencing on December 20, 2015. As of December 31, 2017, the outstanding balance under the Building Loan totaled
$10.9 million
.
The Building Loan is collateralized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than
2.00
to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. We were in compliance with all covenants under the Building Loan as of
December 31, 2017
.
Successor 2022 Second Lien Notes
On the Effective Date, pursuant to the terms of the Plan, the Successor Company entered into an indenture by and among the Company, Stone Offshore, as guarantor (the “Guarantor”), and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (the “2022 Second Lien Notes Indenture”), and issued
$225 million
of the Company’s 2022 Second Lien Notes pursuant thereto.
Interest on the 2022 Second Lien Notes accrues at a rate of
7.50%
per annum payable semi-annually in arrears on May 31 and November 30 of each year in cash, beginning November 30, 2017. At December 31, 2017,
$1.4 million
had been accrued in connection with the May 31, 2018 interest payment. The 2022 Second Lien Notes are secured on a second lien priority basis by the same collateral that secures the Amended Credit Agreement, including the Company’s oil and natural gas properties, and are guaranteed by the Guarantor. The 2022 Second Lien Notes mature on May 31, 2022. Pursuant to the terms of the Intercreditor Agreement (as defined below), the security interest in those assets that secure the 2022 Second Lien Notes and the related guarantee
are contractually subordinated to liens thereon that secure the Company’s Amended Credit Agreement and certain other permitted obligations as set forth in the 2022 Second Lien Notes Indenture. Consequently, the 2022 Second Lien Notes and the related guarantee are effectively subordinated to the Amended Credit Agreement and such other permitted secured indebtedness to the extent of the value of such assets.
At any time prior to May 31, 2020, the Company may, at its option, on any one or more occasions redeem up to
35%
of the aggregate principal amount of the 2022 Second Lien Notes issued under the 2022 Second Lien Notes Indenture at a redemption price of
107.5%
of the principal amount of the 2022 Second Lien Notes, plus accrued and unpaid interest to the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings; provided that at least
65%
of the aggregate principal amount of the 2022 Second Lien Notes as of the Effective Date remains outstanding after each such redemption. On or after May 31, 2020, the Company may redeem all or part of the 2022 Second Lien Notes at redemption prices (expressed as percentages of the principal amount) equal to (i)
105.625%
for the twelve-month period beginning on May 31, 2020; (ii)
105.625%
for the twelve-month period beginning on May 31, 2021; and (iii)
100.000%
for the twelve-month period beginning on May 31, 2022 and at any time thereafter, in each case, plus accrued and unpaid interest at the redemption date. In addition, at any time prior to May 31, 2020, the Company may redeem all or a part of the 2022 Second Lien Notes at a redemption price equal to
100%
of the principal amount of the 2022 Second Lien Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
The 2022 Second Lien Notes Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue preferred stock; (ii) make payments or distributions on account of the Company’s or its restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of the Company’s 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 2022 Second Lien Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and no Default (as defined in the 2022 Second Lien Notes Indenture) has occurred and is continuing, many of these covenants will terminate.
The 2022 Second Lien Notes Indenture also provides for certain events of default. In the case of an event of default arising from certain events of bankruptcy, insolvency or reorganization with respect to the Company or any of the Company’s restricted subsidiaries that is a significant subsidiary, or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, all outstanding 2022 Second Lien Notes will become due and immediately payable without further action or notice. If any other event of default occurs and is continuing, the trustee of the 2022 Second Lien Notes or the holders of at least
25%
in aggregate principal amount of the then outstanding 2022 Second Lien Notes may declare all the 2022 Second Lien Notes to be due and payable immediately.
Intercreditor Agreement
On the Effective Date, Bank of America, N.A., as priority lien agent, The Bank of New York Mellon Trust Company, N.A., as second lien collateral agent, and The Bank of New York Mellon Trust Company, N.A., as the 2022 Second Lien Notes trustee, entered into an intercreditor agreement, which was acknowledged and agreed to by the Company and the Guarantor (the “Intercreditor Agreement”) to govern the relationship of holders of the 2022 Second Lien Notes, the lenders under the Amended Credit Agreement and holders of other priority lien obligations, with respect to collateral and certain other matters.
Predecessor Senior Notes
2017 Convertible Notes.
On March 6, 2012, the Predecessor Company issued in a private offering
$300 million
in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. The 2017 Convertible Notes were convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of
23.4449
shares of our common stock per
$1,000
principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately
$42.65
per share of our common stock at the time of the issuance of the 2017 Convertible Notes. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock and proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of
2.34449
shares of our common stock with a corresponding conversion price of
$426.50
per share.
The 2017 Convertible Notes were due on March 1, 2017. Upon emergence from bankruptcy on February 28, 2017, pursuant to the Plan, the
$300 million
of debt related to the 2017 Convertible Notes was cancelled. See
Note 2 – Reorganization
for additional details.
During the year ended
December 31, 2016
(Predecessor), we recognized
$15.4 million
of interest expense for the amortization of the discount and
$1.5 million
of interest expense for the amortization of debt issuance costs related to the 2017 Convertible Notes. During the year ended
December 31, 2015
(Predecessor), we recognized
$15.0 million
of interest expense for the amortization of the discount and
$1.4 million
of interest expense for the amortization of debt issuance costs related to the 2017 Convertible Notes.
2022 Notes.
On November 8, 2012 and November 27, 2013, respectively, the Predecessor Company completed the public offering of
$300 million
and
$475 million
aggregate principal amount of the 2022 Notes. The 2022 Notes were scheduled to mature on November 15, 2022. Upon emergence from bankruptcy, pursuant to the Plan, the
$775 million
of debt related to the 2022 Notes was cancelled. See
Note 2 – Reorganization
for additional details.
Deferred Financing Cost and Interest Cost
In accordance with the provisions of ASC 852, we recognized a charge of approximately
$8.3 million
to write-off the remaining unamortized debt issuance costs, discounts and premiums related to the 2017 Convertible Notes and 2022 Notes, which is included in reorganization items in the accompanying consolidated statement of operations for the year ended December 31, 2016 (Predecessor). Additionally, we recognized a charge of approximately
$2.6 million
to write-off the remaining unamortized debt issuance costs related to the Pre-Emergence Credit Agreement as of the Petition Date, which is included in reorganization items in the consolidated statement of operations during the period from January 1, 2017 through February 28, 2017 (Predecessor). See
Note 1 – Organization and Summary of Significant Accounting Policies
and
Note 3 – Fresh Start Accounting
for additional details.
At December 31, 2017 (Successor) and December 31, 2016 (Predecessor), approximately
$59 thousand
and
$63 thousand
, respectively, of unamortized debt issuance costs were deducted from the carrying amount of the Building Loan. At December 31, 2016 (Predecessor), approximately
$2.8 million
of debt issuance costs related to the Pre-Emergence Credit Agreement were classified as other assets.
Prior to the filing of the Bankruptcy Petitions, the costs associated with the 2017 Convertible Notes were being amortized over the life of the notes using a method that applied an effective interest rate of
7.51%
. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes were being amortized over the life of the notes using a method that applied effective interest rates of
7.75%
and
7.04%
, respectively. The costs associated with the Pre-Emergence Credit Agreement were being amortized on a straight-line basis over the term of the facility. The costs associated with the issuance of the Building Loan are being amortized using the effective interest method over the term of the Building Loan.
Total interest cost incurred, before capitalization, on all obligations for the period from March 1, 2017 through December 31, 2017 (Successor) was
$15.7 million
. Total interest cost incurred, before capitalization, on all obligations for the years ended December 31,
2016
and
2015
(Predecessor) was
$91.1 million
and
$85.3 million
, respectively. In accordance with the accounting guidance in ASC 852, we accrued interest on the 2017 Convertible Notes and 2022 Notes only up to the Petition Date, and such amounts were included as liabilities subject to compromise in our consolidated balance sheet at December 31, 2016 (Predecessor). Accordingly, there was
no
interest expense recognized on the 2017 Convertible Notes or the 2022 Notes after the Bankruptcy Petitions were filed.
NOTE 14 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts, and accordingly, changes in the fair value of the derivative were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. We had
no
outstanding derivative contracts at December 31, 2016.
During the periods from March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor), we entered into various commodity derivative contracts (see
Note 9 – Derivative Instruments and Hedging Activities
). With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense).
During the year ended December 31, 2016, we reclassified a
$6.1 million
loss related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC.
The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
|
Foreign
Currency
Items
|
|
Total
|
|
For the Year Ended December 31, 2016 (Predecessor)
|
|
|
|
|
|
|
Beginning balance, net of tax
|
$
|
24,025
|
|
|
$
|
(6,073
|
)
|
|
$
|
17,952
|
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
Change in fair value of derivatives
|
(1,648
|
)
|
|
—
|
|
|
(1,648
|
)
|
|
Foreign currency translations
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
|
Income tax effect
|
581
|
|
|
—
|
|
|
581
|
|
|
Net of tax
|
(1,067
|
)
|
|
(8
|
)
|
|
(1,075
|
)
|
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
Operating revenue: oil/natural gas production
|
35,457
|
|
|
—
|
|
|
35,457
|
|
|
Other operational expenses
|
—
|
|
|
(6,081
|
)
|
|
(6,081
|
)
|
|
Income tax effect
|
(12,499
|
)
|
|
—
|
|
|
(12,499
|
)
|
|
Net of tax
|
22,958
|
|
|
(6,081
|
)
|
|
16,877
|
|
|
Other comprehensive income (loss), net of tax
|
(24,025
|
)
|
|
6,073
|
|
|
(17,952
|
)
|
|
Ending balance, net of tax
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
|
Foreign
Currency
Items
|
|
Total
|
|
For the Year Ended December 31, 2015 (Predecessor)
|
|
|
|
|
|
|
Beginning balance, net of tax
|
$
|
86,783
|
|
|
$
|
(3,468
|
)
|
|
$
|
83,315
|
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
Change in fair value of derivatives
|
52,630
|
|
|
—
|
|
|
52,630
|
|
|
Foreign currency translations
|
—
|
|
|
(2,605
|
)
|
|
(2,605
|
)
|
|
Income tax effect
|
(19,096
|
)
|
|
—
|
|
|
(19,096
|
)
|
|
Net of tax
|
33,534
|
|
|
(2,605
|
)
|
|
30,929
|
|
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
Operating revenue: oil/natural gas production
|
149,955
|
|
|
—
|
|
|
149,955
|
|
|
Derivative income, net
|
1,170
|
|
|
—
|
|
|
1,170
|
|
|
Income tax effect
|
(54,833
|
)
|
|
—
|
|
|
(54,833
|
)
|
|
Net of tax
|
96,292
|
|
|
—
|
|
|
96,292
|
|
|
Other comprehensive loss, net of tax
|
(62,758
|
)
|
|
(2,605
|
)
|
|
(65,363
|
)
|
|
Ending balance, net of tax
|
$
|
24,025
|
|
|
$
|
(6,073
|
)
|
|
$
|
17,952
|
|
NOTE 15 — EMPLOYEE BENEFIT PLANS
We entered into deferred compensation and disability agreements with certain of our former officers. The benefits under the deferred compensation agreements vested after certain periods of employment, and at
December 31, 2017
(Successor), the liability for such vested benefits was approximately
$0.9 million
and is recorded in current and other long-term liabilities. The deferred compensation plan is described further below.
The following is a brief description of each incentive compensation plan applicable to our employees:
Annual Incentive Cash Compensation Plans
In 2016, we replaced our historical long-term cash and equity-based incentive compensation programs with the 2016 Performance Incentive Compensation Plan (the “2016 Annual Incentive Plan”), pursuant to which incentive cash bonuses were
calculated based on the achievement of certain strategic objectives for each quarter of 2016. On July 25, 2017, the Board approved the Stone Energy Corporation 2017 Annual Incentive Compensation Plan (the “2017 Annual Incentive Plan”) for all salaried employees (other than the interim chief executive officer) of the Company. The 2017 Annual Incentive Plan is a performance-based short-term cash incentive program that provides award opportunities based on the Company’s annual performance in certain performance measures as defined by the Board. The 2017 Annual Incentive Plan replaced the Company’s Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, and the 2016 Annual Incentive Plan.
For the period from March 1, 2017 through December 31, 2017 (Successor), Stone incurred expenses of
$7.0 million
, net of amounts capitalized, related to incentive compensation cash bonuses. Stone incurred expenses of
$13.5 million
and
$2.2 million
,
net of amounts capitalized, for each of the years ended
December 31, 2016
and
2015
(Predecessor), respectively, related to incentive compensation cash bonuses. These charges are reflected in incentive compensation expense on the statement of operations.
Key Executive Incentive Plan
Pursuant to the terms of the Executive Claims Settlement Agreement, the Company’s executives agreed to waive their claims related to the Company’s 2016 Annual Incentive Plan, and in exchange therefor, the Company adopted the Stone Energy Corporation Key Executive Incentive Plan (“KEIP”), in which the Company’s executives were allowed to participate. Payments to the Company’s executives under the KEIP were limited to
$2.0 million
, or the equivalent of the target bonus under the 2016 Annual Incentive Plan for the fourth quarter of 2016. The KEIP payments of
$2.0 million
are reflected in incentive compensation expense on the statement of operations for the period from January 1, 2017 through February 28, 2017 (Predecessor).
Retention Award Agreement
On July 25, 2017, the Board approved retention awards and the form of Stone Energy Corporation Retention Award Agreement (the “Retention Award Agreement”) and authorized the Company to enter into Retention Award Agreements with certain executive officers and employees of the Company. The Retention Award Agreement provides for a retention award to certain individuals to be paid in a lump sum cash payment within
30
days of the earliest to occur of (i) the first anniversary (June 1, 2018) of the effective date of the Retention Award Agreement, subject to the individual remaining employed by the Company or a subsidiary of the Company on such date, (ii) a change in control of the Company or (iii) a termination of the individual’s employment with the Company (a) due to death, (b) by the Company without “cause” or (c) by the individual for “good reason.” We recognized a charge of
$1.0 million
for the period from March 1, 2017 through December 31, 2017 (Successor), representing a prorated portion of estimated retention awards through December 31, 2017. This charge is reflected in incentive compensation expense on the statement of operations.
Transaction Bonus Agreement
On November 21, 2017, the Board approved transaction bonuses and the form of Stone Energy Corporation Transaction Bonus Agreement (the “Transaction Bonus Agreement”) and authorized the Company to enter into Transaction Bonus Agreements with certain of our executive officers and other employees of the Company. The Transaction Bonus Agreements provide for a lump sum cash payment within
30
days of a “change in control” (as defined in the Transaction Bonus Agreement) if the individual remains employed with the Company through the date of the “change in control” or is terminated prior to the change in control (i) due to death, (ii) by the Company without “cause” (as defined below) (including due to disability), or (iii) by the individual for “good reason” (as defined in the Transaction Bonus Agreement). The Transaction Bonus Agreements were entered into in connection with the Talos combination.
2017 Long-Term Incentive Plan
On the Effective Date, pursuant to the Plan, the Stone Energy Corporation 2017 Long-Term Incentive Plan (the “2017 LTIP”) became effective, replacing the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015). The types of awards that may be granted under the 2017 LTIP include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards. The maximum number of shares of New Common Stock that may be issued or transferred pursuant to awards under the 2017 LTIP is
2,614,379
. As of
March 9, 2018
, other than the grant of
62,137
restricted stock units to the Board (see
Note 16 – Share-Based Compensation
), there have been no other issuances or awards of stock under the 2017 LTIP.
401(k) and Deferred Compensation Plans
The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each employee. An employee is
20%
vested in matching contributions (if any) for each year of service and is fully vested upon
five
years of service. For the period from March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), Stone contributed
$0.6 million
and
$0.3 million
, respectively, to the plan. For the years ended
December 31, 2016
and
2015
(Predecessor), Stone contributed
$1.2 million
and
$1.6 million
, respectively, to the plan.
The Stone Energy Corporation Deferred Compensation Plan (the “Deferred Compensation Plan”) provides eligible executives and employees with the option to defer up to
100%
of their eligible compensation for a calendar year. Historically, we could, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our Board. In 2016, the compensation committee of the Predecessor board adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under such plan. Our Board may still elect to make discretionary profit sharing contributions to the plan. To date, there have been no matching or discretionary profit sharing contributions made by Stone under the Deferred Compensation Plan. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At
December 31, 2017
(Successor) and December 31,
2016
(Predecessor), plan assets of
$5.1 million
and
$8.7 million
, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.
Change of Control and Severance Plans
On July 25, 2017, the Board approved the Stone Energy Corporation Executive Severance Plan (the “Executive Severance Plan”), which provides for the payment of severance and change in control benefits to the executive officers (other than the interim chief executive officer) of the Company. The Executive Severance Plan replaced the Stone Energy Corporation Executive Severance Plan dated December 13, 2016. Pursuant to the Executive Severance Plan, if a covered executive officer is terminated (i) by the Company without “cause” or (ii) by the executive officer for “good reason” (each, an “Involuntary Termination”), the executive officer will receive (i) a lump sum cash payment in an amount equal to
1.0
x or
1.5
x the executive officer’s annual base salary, (ii) a lump sum cash payment equal to
100%
of the executive officer’s annual bonus opportunity, at target, prorated by the number of days that have elapsed from January 1 of that calendar year, (iii) six months of health benefit continuation for the executive officer and the executive officer’s dependents, at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iv) accelerated vesting of any outstanding and unvested equity awards, (v) certain outplacement services and (vi) any unpaid portion of the executive officer’s annual pay as of the date of the Involuntary Termination. The Executive Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year.
On July 25, 2017, the Board approved the Stone Energy Corporation Employee Severance Plan (the “2017 Employee Severance Plan”). The 2017 Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the twelve-month period following a change of control. Employees who are terminated within the scope of the 2017 Employee Severance Plan will be entitled to certain payments and benefits including the following: (i) a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full
$10 thousand
of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay, (ii) continued health plan coverage for
6 months
at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iii) a prorated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. The 2017 Employee Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year. The 2017 Employee Severance Plan replaced the Stone Energy Corporation Employee Change of Control Severance Plan, dated December 7, 2007.
NOTE 16 — SHARE-BASED COMPENSATION
On the Effective Date, pursuant to the Plan, the 2017 LTIP became effective. As discussed in
Note 15 – Employee Benefit Plans
, the types of awards that may be granted under the 2017 LTIP include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards.
We record share-based compensation expense for share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our statement of operations on a straight-line basis over the vesting period of the award. Under the full cost method of accounting, we capitalize a portion of employee and general and administrative costs (including share-based compensation). Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.
Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital and/or an increase in income tax expense, depending on the pool of available excess tax benefits to offset such deficit. There were
no
adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting in
2017
,
2016
or
2015
. During the period from March 1, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31,
2016
and
2015
(Predecessor), respectively,
$2.5 million
,
$2.7 million
,
$4.1 million
and
$1.3 million
of tax deficits were charged to income tax expense.
Predecessor Share-Based Compensation
For the period from January 1, 2017 through February 28, 2017 (Predecessor), we incurred
$3.5 million
of share-based compensation expense, all of which related to stock awards and restricted stock issuances, and of which a total of approximately
$0.9 million
was capitalized into oil and gas properties. For the year ended
December 31, 2016
(Predecessor), we incurred
$11.6 million
of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately
$3.1 million
was capitalized into oil and gas properties. For the year ended
December 31, 2015
(Predecessor), we incurred
$17.9 million
of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately
$5.6 million
was capitalized into oil and gas properties.
Stock Options
.
All outstanding stock options at December 31, 2016 related to executive share-based awards that were cancelled upon emergence from bankruptcy. There were
no
stock option grants during the period from January 1, 2017 through February 28, 2017. The following tables include Predecessor Company stock option activity during the years ended December 31, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016 (Predecessor)
|
|
|
Number
of
Options
|
|
Wgtd.
Avg.
Exercise
Price
|
|
Wgtd.
Avg.
Term
|
|
Aggregate
Intrinsic
Value
|
|
Options outstanding, beginning of period
|
14,447
|
|
|
$
|
269.25
|
|
|
|
|
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
|
|
|
|
Forfeited
|
—
|
|
|
—
|
|
|
|
|
|
|
Expired
|
(1,500
|
)
|
|
477.45
|
|
|
|
|
|
|
Options outstanding, end of period
|
12,947
|
|
|
245.13
|
|
|
1.4 years
|
|
|
$
|
—
|
|
|
Options exercisable, end of period
|
12,947
|
|
|
245.13
|
|
|
1.4 years
|
|
|
—
|
|
|
Options unvested, end of period
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015 (Predecessor)
|
|
|
Number
of
Options
|
|
Wgtd.
Avg.
Exercise
Price
|
|
Wgtd.
Avg.
Term
|
|
Aggregate
Intrinsic
Value
|
|
Options outstanding, beginning of period
|
20,497
|
|
|
$
|
339.36
|
|
|
|
|
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
|
|
|
|
Forfeited
|
—
|
|
|
—
|
|
|
|
|
|
|
Expired
|
(6,050
|
)
|
|
506.76
|
|
|
|
|
|
|
Options outstanding, end of period
|
14,447
|
|
|
269.25
|
|
|
2.1 years
|
|
|
$
|
—
|
|
|
Options exercisable, end of period
|
14,447
|
|
|
269.25
|
|
|
2.1 years
|
|
|
—
|
|
|
Options unvested, end of period
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Restricted Stock and Other Stock Awards.
Immediately prior to emergence, the vesting of all Predecessor outstanding, unvested share-based awards for non-executive employees was accelerated and, as a result, all unrecognized compensation cost related to such awards was recognized. Upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for a proportionate share of the
5%
of New Common Stock, plus a proportionate share of the warrants for ownership of up to
15%
of the Successor Company’s common equity. Vesting continued in accordance with the applicable vesting provisions of the original awards (see
Successor Share-Based Compensation
below).
During the period from January 1, 2017 through February 28, 2017,
10,404
shares (valued at
$69 thousand
) of Predecessor Company stock were issued, representing grants of stock to the board of directors of the Predecessor Company. During the years ended
December 31, 2016
and 2015, we issued
31,313
shares (valued at
$0.3 million
) and
141,872
shares (valued at
$23.7 million
), respectively, of Predecessor Company restricted stock or stock awards.
The following table includes Predecessor Company restricted stock and stock award activity during the period from January 1, 2017 through February 28, 2017 and the years ended December 31, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
2016
|
|
2015
|
|
|
|
Number of
Restricted
Shares
|
|
Wgtd.
Avg.
Fair Value
Per Share
|
|
Number of
Restricted
Shares
|
|
Wgtd.
Avg.
Fair Value
Per Share
|
|
Number of
Restricted
Shares
|
|
Wgtd.
Avg.
Fair Value
Per Share
|
|
Restricted stock outstanding, beginning of period
|
|
81,090
|
|
|
$
|
205.34
|
|
|
180,239
|
|
|
$
|
208.17
|
|
|
129,848
|
|
|
$
|
299.45
|
|
|
Issuances
|
|
10,404
|
|
|
6.67
|
|
|
31,313
|
|
|
8.93
|
|
|
141,872
|
|
|
167.21
|
|
|
Lapse of restrictions or granting of stock awards
|
|
(73,276
|
)
|
|
186.37
|
|
|
(117,406
|
)
|
|
158.79
|
|
|
(63,745
|
)
|
|
296.00
|
|
|
Forfeitures
|
|
(194
|
)
|
|
169.40
|
|
|
(13,056
|
)
|
|
200.06
|
|
|
(27,736
|
)
|
|
223.80
|
|
|
Restricted stock outstanding, end of period
|
|
18,024
|
|
|
$
|
169.42
|
|
|
81,090
|
|
|
$
|
205.34
|
|
|
180,239
|
|
|
$
|
208.17
|
|
Successor Share-Based Compensation
Restricted Stock and Other Stock Awards.
As discussed above, upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for proportionate shares of New Common Stock. Vesting continued in accordance with the applicable vesting provisions of the original awards, with remaining compensation expense based on the fresh start fair value of
$26.95
per share (see
Note 3 – Fresh Start Accounting
).
For the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately
$0.1 million
of share-based compensation expense related to these restricted shares. The restricted stock outstanding on December 31, 2017 became fully vested on January 15, 2018. The following table includes Successor Company restricted stock and stock award activity during the period from March 1, 2017 through December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from March 1, 2017 through December 31, 2017
|
|
|
|
Number of
Restricted
Shares
|
|
Wgtd.
Avg.
Fair Value
Per Share
|
|
Restricted stock outstanding at February 28, 2017 (Predecessor)
|
|
18,024
|
|
|
$
|
169.42
|
|
|
Restricted stock outstanding at March 1, 2017 (Successor)
|
|
3,176
|
|
|
$
|
26.95
|
|
|
Issuances
|
|
—
|
|
|
—
|
|
|
Lapse of restrictions
|
|
(2,083
|
)
|
|
21.78
|
|
|
Forfeitures
|
|
—
|
|
|
—
|
|
|
Restricted stock outstanding at December 31, 2017 (Successor)
|
|
1,093
|
|
|
$
|
26.95
|
|
Restricted Stock Units.
On March 1, 2017, the Board received grants of restricted stock units under the 2017 LTIP. The restricted stock units are scheduled to vest in full on the day prior to the annual meeting of the Company’s stockholders in May 2018, subject to: (i) the director’s continued service on the board through the vesting date, and (ii) earlier vesting upon the occurrence of a change of control event or the termination of the director’s service due to death or removal from the board without cause. A total of
62,137
restricted stock units were granted with an aggregate grant date fair value of
$1.7 million
, based on a per share grant date fair value of
$26.95
. During the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately
$1.2 million
of share-based compensation expense related to these restricted stock units. As of December 31, 2017, there was
$0.5 million
of unrecognized compensation cost related to such restricted stock units, with a current weighted average remaining vesting period of approximately
four
months.
NOTE 17 — REDUCTION IN WORKFORCE
During the second quarter of 2017, we implemented workforce reduction plans to better align our employee base with current business needs, resulting in a reduction of approximately
20%
of our total workforce. The workforce reductions were complete as of July 31, 2017. In connection with the reductions, we recognized a charge of
$5.7 million
, consisting primarily of severance payments to affected employees and payment of related employer payroll taxes. This charge is reflected in SG&A expenses on the statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor).
In addition to the workforce reduction costs, during the second quarter of 2017, we recognized a charge of
$3.0 million
for severance costs related to the sale of the Appalachia Properties and the retirement of the prior chief executive officer of the Company. These severance costs are reflected in SG&A expenses on the statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor).
NOTE 18 — FEDERAL ROYALTY RECOVERY
In July 2017, we received a federal royalty recovery totaling
$14.1 million
as part of a multi-year federal royalty refund claim. Approximately
$9.6 million
of the refund was recognized as other operational income and
$4.5 million
as a reduction of lease operating expenses during the period from March 1, 2017 through December 31, 2017 (Successor). Included in SG&A expenses for the period from March 1, 2017 through December 31, 2017 (Successor) is a
$3.9 million
success-based consulting fee incurred in connection with the federal royalty recovery.
NOTE 19 — OTHER OPERATIONAL EXPENSES
Other operational expenses for the period of March 1, 2017 through December 31, 2017 (Successor) of
$3.4 million
included approximately
$2.1 million
of stacking charges for the Pompano platform rig. For the year ended December 31, 2016 (Predecessor), other operational expenses of
$55.5 million
included approximately
$17.7 million
of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a
$20.0 million
charge related to the termination of our deep water drilling rig contract with Ensco and
$9.9 million
in charges related to the terminations of offshore vessel and Appalachian drilling rig contracts. Also included in other operational expenses for the year ended December 31, 2016 (Predecessor) is a
$6.1 million
loss on the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See
Note 14 – Accumulated Other Comprehensive Income (Loss)
.
NOTE 20 — COMBINATION TRANSACTION COSTS
In connection with the pending combination with Talos, we have incurred approximately
$6.2 million
in transaction costs, consisting primarily of legal and financial advisor costs. These costs are included in SG&A expense on our statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor). Additionally, we have incurred approximately
$0.2 million
of direct costs for purposes of registering equity securities to effect the Talos combination. These direct costs are recorded as a reduction of additional paid-in-capital during the period from March 1, 2017 through December 31, 2017 (Successor). See
Note 1 – Organization and Summary of Significant Accounting Policies
for more information on the pending combination.
NOTE 21 — COMMITMENTS AND CONTINGENCIES
Legal Proceedings
We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.
Leases
We lease office facilities in Lafayette and New Orleans, Louisiana under the terms of non-cancelable leases expiring on various dates in
2018
. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net commitment for 2018 under our leases, subleases and contracts
at
December 31, 2017
totaled
$0.3 million
.
Payments related to our lease obligations were
$0.5 million
for the period from March 1, 2017 through December 31, 2017 (Successor) and
$0.1 million
for the period of January 1, 2017 through February 28, 2017 (Predecessor). Payments related to our lease obligations for the years ended
December 31, 2016
and
2015
(Predecessor) were approximately
$0.7 million
and
$3.1 million
, respectively.
Other Commitments and Contingencies
On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately
$115 million
in surety bonds in favor of BOEM, third-party bonds, and letters of credit, all relating to our offshore abandonment obligations.
In July 2016, BOEM issued a Notice to Lessees (the “NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of OCS facilities) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.
We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017.
In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when, or if, the July 2016 NTL will be implemented or whether a revised NTL might be proposed. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with
BOEM and the Bureau of Safety and Environmental Enforcement, and any modifications to the proposed NTL. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.
In connection with our exploration and development efforts, we are contractually committed to the acquisition of seismic data in the amount of
$8.6 million
to be incurred over the next
two
years.
The Oil Pollution Act (“OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than
1,000
barrels must demonstrate financial responsibility in amounts ranging from at least
$10 million
in specified state waters to at least
$35 million
in Outer Continental Shelf waters, with higher amounts of up to
$150 million
in certain limited circumstances where BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under BOEM’s final rule. In addition, BOEM has finalized rules that raise OPA’s damages liability cap from
$75 million
to
$133.7 million
.
NOTE 22 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED
At
December 31, 2017
and
2016
, our oil and gas properties were located in the United States (onshore and offshore). On February 27, 2017, we completed the sale of the Appalachia Properties in connection with our restructuring (see
Note 4 – Divestiture
). During
2015
, we discontinued our business development effort in Canada.
With the adoption of fresh start accounting, the Company recorded its oil and gas properties at fair value as of February 28, 2017. The Company’s proved, probable and possible reserves and unevaluated properties (including inventory) were assigned values of
$380.8 million
,
$16.8 million
and
$80.2 million
, respectively. See
Note 3 – Fresh Start Accounting
for a discussion of the valuation approach used.
Costs Incurred
United States
. The following table discloses the total amount of capitalized costs and accumulated DD&A relative to our proved and unevaluated oil and natural gas properties located in the United States (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31, 2017
|
|
|
December 31, 2016
|
|
Proved properties
|
$
|
713,157
|
|
|
|
$
|
9,572,082
|
|
|
Unevaluated properties
|
102,187
|
|
|
|
373,720
|
|
|
Total proved and unevaluated properties
|
815,344
|
|
|
|
9,945,802
|
|
|
Less accumulated depreciation, depletion and amortization
|
(353,462
|
)
|
|
|
(9,134,288
|
)
|
|
Balance, end of year
|
$
|
461,882
|
|
|
|
$
|
811,514
|
|
The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States during the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from March 1, 2017 through December 31, 2017
|
|
|
Period from January 1, 2017 through February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Costs incurred during the period (capitalized):
|
|
|
|
|
|
|
|
|
|
Acquisition costs, net of sales of unevaluated properties
|
$
|
(8,371
|
)
|
|
|
$
|
(324
|
)
|
|
$
|
3,923
|
|
|
$
|
(14,158
|
)
|
|
Exploratory costs
|
12,079
|
|
|
|
2,055
|
|
|
17,891
|
|
|
104,169
|
|
|
Development costs (1)
|
33,356
|
|
|
|
12,547
|
|
|
102,665
|
|
|
266,982
|
|
|
Salaries, general and administrative costs
|
7,495
|
|
|
|
2,976
|
|
|
21,753
|
|
|
27,984
|
|
|
Interest
|
3,927
|
|
|
|
2,524
|
|
|
26,634
|
|
|
41,339
|
|
|
Less: overhead reimbursements
|
(1,004
|
)
|
|
|
—
|
|
|
(521
|
)
|
|
(913
|
)
|
|
Total costs incurred during the period, net of divestitures
|
$
|
47,482
|
|
|
|
$
|
19,778
|
|
|
$
|
172,345
|
|
|
$
|
425,403
|
|
(1) Includes net changes in capitalized asset retirement costs of
($17,446)
,
$0
,
($4,461)
and
($43,901)
, respectively.
The following table discloses operational expenses incurred during the periods indicated relative to our oil and natural gas producing activities located in the United States (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from
March 1, 2017
through
December 31, 2017
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Lease operating expenses
|
$
|
49,800
|
|
|
|
$
|
8,820
|
|
|
$
|
79,650
|
|
|
$
|
100,139
|
|
|
Transportation, processing and gathering expenses
|
4,084
|
|
|
|
6,933
|
|
|
27,760
|
|
|
58,847
|
|
|
Production taxes
|
629
|
|
|
|
682
|
|
|
3,148
|
|
|
6,877
|
|
|
Accretion expense
|
21,151
|
|
|
|
5,447
|
|
|
40,229
|
|
|
25,988
|
|
|
Expensed costs – United States
|
$
|
75,664
|
|
|
|
$
|
21,882
|
|
|
$
|
150,787
|
|
|
$
|
191,851
|
|
The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties in the United States for the periods indicated (in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from March 1, 2017 through December 31, 2017
|
|
|
Period from January 1, 2017 through February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Provision for DD&A
|
$
|
97,027
|
|
|
|
$
|
36,751
|
|
|
$
|
215,737
|
|
|
$
|
277,088
|
|
|
Write-down of oil and gas properties
|
$
|
256,435
|
|
|
|
$
|
—
|
|
|
$
|
357,079
|
|
|
$
|
1,314,817
|
|
|
DD&A per Boe
|
$
|
16.61
|
|
|
|
$
|
17.05
|
|
|
$
|
16.10
|
|
|
$
|
19.15
|
|
At March 31, 2017 (Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of
$256.4 million
based on twelve-month average prices, net of applicable differentials, of
$45.40
per Bbl of oil,
$2.24
per Mcf of natural gas and
$19.18
per Bbl of NGLs. The write-down at March 31, 2017 is reflected in the statement of operations of the Successor Company for the period from March 1, 2017 through December 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were
$56.01
per Bbl of oil,
$2.52
per Mcf of natural gas and
$14.18
per Bbl of NGLs, net of applicable differentials.
Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (see
Note 9 – Derivative Instruments and Hedging Activities
), the write-down at March 31, 2017 was not affected by hedging. The 2016 and 2015 write-downs were decreased by
$50.7 million
and
$143.9 million
, respectively, as a result of hedges.
The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from March 1, 2017 through December 31, 2017
|
|
|
Period from January 1, 2017 through February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Net costs incurred (evaluated) during period:
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
$
|
(9,155
|
)
|
|
|
$
|
959
|
|
|
$
|
(71,378
|
)
|
|
$
|
(115,767
|
)
|
|
Exploration costs
|
10,405
|
|
|
|
(6,063
|
)
|
|
(21,579
|
)
|
|
(16,315
|
)
|
|
Capitalized interest
|
3,927
|
|
|
|
2,524
|
|
|
26,634
|
|
|
41,339
|
|
|
|
$
|
5,177
|
|
|
|
$
|
(2,580
|
)
|
|
$
|
(66,323
|
)
|
|
$
|
(90,743
|
)
|
Under fresh start accounting, our oil and gas properties were recorded at fair value as of February 28, 2017. The following table discloses financial data associated with unevaluated costs (United States) for the Successor Company at
December 31, 2017
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
Net Costs Incurred During the Period from March 1, 2017 through December 31, 2017
|
|
Successor
|
|
March 1, 2017
|
|
December 31, 2017
|
|
Acquisition costs
|
$
|
58,359
|
|
|
$
|
(9,155
|
)
|
|
$
|
49,204
|
|
|
Exploration costs
|
38,651
|
|
|
10,405
|
|
|
49,056
|
|
|
Capitalized interest
|
—
|
|
|
3,927
|
|
|
3,927
|
|
|
Total unevaluated costs
|
$
|
97,010
|
|
|
$
|
5,177
|
|
|
$
|
102,187
|
|
Approximately
34
specifically identified drilling projects are included in unevaluated costs at
December 31, 2017
and are expected to be evaluated in the next
four
years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined.
Canada
. During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices, we discontinued our business development effort in Canada during 2015 and recognized a full impairment of our Canadian oil and gas properties. The following table discloses certain financial data relative to our oil and gas activities located in Canada (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
Oil and gas properties – Canada:
|
|
|
|
|
|
Balance, beginning of year
|
|
$
|
42,484
|
|
|
$
|
36,579
|
|
|
Costs incurred during the year (capitalized):
|
|
|
|
|
|
Acquisition costs
|
|
(498
|
)
|
|
(2,862
|
)
|
|
Exploratory costs
|
|
2,168
|
|
|
8,767
|
|
|
Total costs incurred during the year
|
|
1,670
|
|
|
5,905
|
|
|
Balance, end of year (fully evaluated at December 31, 2016 and 2015)
|
|
$
|
44,154
|
|
|
$
|
42,484
|
|
|
Accumulated DD&A:
|
|
|
|
|
|
Balance, beginning of year
|
|
$
|
(42,484
|
)
|
|
$
|
—
|
|
|
Foreign currency translation adjustment
|
|
(1,318
|
)
|
|
5,146
|
|
|
Write-down of oil and gas properties
|
|
(352
|
)
|
|
(47,630
|
)
|
|
Balance, end of year
|
|
$
|
(44,154
|
)
|
|
$
|
(42,484
|
)
|
|
Net capitalized costs – Canada
|
|
$
|
—
|
|
|
$
|
—
|
|
Proved Oil and Natural Gas Quantities
Our estimated net proved oil and natural gas reserves at
December 31, 2017
have been prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.
The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and NGL reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical twelve-month average pricing assumption.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
NGLs
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Oil,
Natural
Gas and
NGLs
(MBoe)
|
|
Estimated proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
As of December 31, 2014 (Predecessor)
|
|
42,397
|
|
|
27,817
|
|
|
493,843
|
|
|
152,520
|
|
|
Revisions of previous estimates
|
|
(6,818
|
)
|
|
(20,777
|
)
|
|
(362,102
|
)
|
|
(87,945
|
)
|
|
Extensions, discoveries and other additions
|
|
862
|
|
|
11
|
|
|
1,499
|
|
|
1,123
|
|
|
Purchase of producing properties
|
|
685
|
|
|
1,808
|
|
|
26,136
|
|
|
6,849
|
|
|
Sale of reserves
|
|
(859
|
)
|
|
—
|
|
|
(1,061
|
)
|
|
(1,036
|
)
|
|
Production
|
|
(5,991
|
)
|
|
(2,401
|
)
|
|
(36,457
|
)
|
|
(14,468
|
)
|
|
As of December 31, 2015 (Predecessor)
|
|
30,276
|
|
|
6,458
|
|
|
121,858
|
|
|
57,043
|
|
|
Revisions of previous estimates
|
|
(751
|
)
|
|
6,352
|
|
|
24,858
|
|
|
9,744
|
|
|
Extensions, discoveries and other additions
|
|
63
|
|
|
2
|
|
|
45
|
|
|
73
|
|
|
Production
|
|
(6,308
|
)
|
|
(2,183
|
)
|
|
(29,441
|
)
|
|
(13,398
|
)
|
|
As of December 31, 2016 (Predecessor)
|
|
23,280
|
|
|
10,629
|
|
|
117,320
|
|
|
53,462
|
|
|
Revisions of previous estimates
|
|
730
|
|
|
(2
|
)
|
|
1,242
|
|
|
935
|
|
|
Sale of reserves
|
|
(826
|
)
|
|
(7,417
|
)
|
|
(52,992
|
)
|
|
(17,075
|
)
|
|
Production
|
|
(908
|
)
|
|
(408
|
)
|
|
(5,037
|
)
|
|
(2,156
|
)
|
|
As of February 28, 2017 (Predecessor)
|
|
22,276
|
|
|
2,802
|
|
|
60,533
|
|
|
35,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
3,769
|
|
|
(94
|
)
|
|
(2,801
|
)
|
|
3,208
|
|
|
Production
|
|
(4,169
|
)
|
|
(403
|
)
|
|
(7,616
|
)
|
|
(5,841
|
)
|
|
As of December 31, 2017 (Successor)
|
|
21,876
|
|
|
2,305
|
|
|
50,116
|
|
|
32,533
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated proved developed reserves:
|
|
|
|
|
|
|
|
|
|
As of December 31, 2015 (Predecessor)
|
|
21,734
|
|
|
4,784
|
|
|
90,262
|
|
|
41,562
|
|
|
As of December 31, 2016 (Predecessor)
|
|
18,269
|
|
|
9,255
|
|
|
90,741
|
|
|
42,647
|
|
|
As of February 28, 2017 (Predecessor)
|
|
18,344
|
|
|
1,515
|
|
|
35,865
|
|
|
25,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017 (Successor)
|
|
20,275
|
|
|
1,689
|
|
|
37,946
|
|
|
28,288
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
As of December 31, 2015 (Predecessor)
|
|
8,542
|
|
|
1,674
|
|
|
31,596
|
|
|
15,481
|
|
|
As of December 31, 2016 (Predecessor)
|
|
5,011
|
|
|
1,374
|
|
|
26,579
|
|
|
10,815
|
|
|
As of February 28, 2017 (Predecessor)
|
|
3,932
|
|
|
1,287
|
|
|
24,668
|
|
|
9,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017 (Successor)
|
|
1,601
|
|
|
616
|
|
|
12,170
|
|
|
4,245
|
|
The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.
2017 Periods.
Revisions of previous estimates were primarily the result of positive well performance (
4
MMBoe). The sale of reserves represents the sale of the Appalachia Properties (
17
MMBoe) in connection with our restructuring (see
Note 4 – Divestiture
).
Year Ended December 31, 2016.
Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs (
15
MMBoe) primarily in Appalachia, slightly offset by negative well performance (
6
MMBoe).
Year Ended December 31, 2015.
Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (
95
MMBoe) primarily in Appalachia, slightly offset by positive well performance (
7
MMBoe). Purchase of producing properties related to increases in our net revenue and working interests in multiple
wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.
Standardized Measure of Discounted Future Net Cash Flows
The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at
December 31, 2017
. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a
10%
annual discount rate. Our GOM Basin properties represented
100%
of our estimated proved oil and natural gas reserves and standardized measure of discounted future net cash flows at December 31, 2017. The standardized measure of discounted future net cash flows and changes therein are as follows (in thousands, except average prices):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31,
|
|
|
December 31,
|
|
|
2017
|
|
|
2016
|
|
2015
|
|
Future cash inflows
|
$
|
1,264,809
|
|
|
|
$
|
1,236,097
|
|
|
$
|
1,921,329
|
|
|
Future production costs
|
(497,538
|
)
|
|
|
(480,815
|
)
|
|
(651,396
|
)
|
|
Future development costs
|
(431,752
|
)
|
|
|
(638,988
|
)
|
|
(679,355
|
)
|
|
Future income taxes
|
—
|
|
|
|
—
|
|
|
—
|
|
|
Future net cash flows
|
335,519
|
|
|
|
116,294
|
|
|
590,578
|
|
|
10% annual discount
|
57,591
|
|
|
|
109,628
|
|
|
13,259
|
|
|
Standardized measure of discounted future net cash flows
|
$
|
393,110
|
|
|
|
$
|
225,922
|
|
|
$
|
603,837
|
|
|
|
|
|
|
|
|
|
|
Average prices related to proved reserves:
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
50.05
|
|
|
|
$
|
40.15
|
|
|
$
|
51.16
|
|
|
NGLs (per Bbl)
|
22.90
|
|
|
|
9.46
|
|
|
16.40
|
|
|
Natural gas (per Mcf)
|
2.34
|
|
|
|
1.71
|
|
|
2.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period from March 1, 2017 through December 31, 2017
|
|
|
Period From January 1, 2017 through February 28, 2017
|
|
Year Ended December 31,
|
|
|
|
|
|
2016
|
|
2015
|
|
Standardized measure at beginning of period
|
$
|
303,086
|
|
|
|
$
|
225,922
|
|
|
$
|
603,837
|
|
|
$
|
1,418,792
|
|
|
Sales and transfers of oil, natural gas and NGLs produced, net of production costs
|
(164,612
|
)
|
|
|
(46,137
|
)
|
|
(223,948
|
)
|
|
(340,477
|
)
|
|
Changes in price, net of future production costs
|
66,192
|
|
|
|
17,455
|
|
|
(448,861
|
)
|
|
(237,747
|
)
|
|
Extensions and discoveries, net of future production and development costs
|
—
|
|
|
|
—
|
|
|
5,243
|
|
|
1,573
|
|
|
Changes in estimated future development costs, net of development costs incurred during the period
|
88,111
|
|
|
|
20,756
|
|
|
54,406
|
|
|
731,115
|
|
|
Revisions of quantity estimates
|
96,454
|
|
|
|
36,557
|
|
|
139,759
|
|
|
(1,458,652
|
)
|
|
Accretion of discount
|
30,309
|
|
|
|
22,592
|
|
|
60,384
|
|
|
174,456
|
|
|
Net change in income taxes
|
—
|
|
|
|
—
|
|
|
—
|
|
|
325,768
|
|
|
Purchases of reserves in-place
|
—
|
|
|
|
—
|
|
|
—
|
|
|
3,493
|
|
|
Sales of reserves in-place
|
—
|
|
|
|
14,584
|
|
|
—
|
|
|
—
|
|
|
Changes in production rates due to timing and other
|
(26,430
|
)
|
|
|
11,357
|
|
|
35,102
|
|
|
(14,484
|
)
|
|
Net change in standardized measure
|
90,024
|
|
|
|
77,164
|
|
|
(377,915
|
)
|
|
(814,955
|
)
|
|
Standardized measure at end of period
|
$
|
393,110
|
|
|
|
$
|
303,086
|
|
|
$
|
225,922
|
|
|
$
|
603,837
|
|
NOTE 23 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED
The Company’s results of operations by quarter are as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
|
Period from
January 1, 2017
through
February 28, 2017
|
|
|
Period from
March 1, 2017
through
March 31, 2017
|
|
2017 Quarter Ended
|
|
|
|
|
June 30
|
|
Sept. 30
|
|
Dec. 31
|
|
Operating revenue
|
$
|
68,922
|
|
|
|
$
|
25,809
|
|
|
$
|
76,722
|
|
|
$
|
79,525
|
|
|
$
|
76,327
|
|
|
Income (loss) from operations
|
$
|
209,119
|
|
|
|
$
|
(258,594
|
)
|
|
$
|
(4,519
|
)
|
|
$
|
2,653
|
|
|
$
|
5,302
|
|
|
Net income (loss)
|
$
|
630,317
|
|
|
|
$
|
(259,613
|
)
|
|
$
|
(6,461
|
)
|
|
$
|
1,297
|
|
|
$
|
17,138
|
|
|
Basic income (loss) per share
|
$
|
110.99
|
|
|
|
$
|
(12.98
|
)
|
|
$
|
(0.32
|
)
|
|
$
|
0.06
|
|
|
$
|
0.86
|
|
|
Diluted income (loss) per share
|
$
|
110.99
|
|
|
|
$
|
(12.98
|
)
|
|
$
|
(0.32
|
)
|
|
$
|
0.06
|
|
|
$
|
0.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Write-down of oil and gas properties
|
$
|
—
|
|
|
|
$
|
256,435
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Gain (loss) on Appalachia Properties divestiture
|
$
|
213,453
|
|
|
|
$
|
—
|
|
|
$
|
27
|
|
|
$
|
(132
|
)
|
|
$
|
—
|
|
|
Reorganization items (1)
|
$
|
(437,744
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other expense
|
$
|
13,336
|
|
|
|
$
|
—
|
|
|
$
|
814
|
|
|
$
|
47
|
|
|
$
|
369
|
|
(1) See
Note 3 – Fresh Start Accounting
for additional details.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
2016 Quarter Ended
|
|
|
March 31
|
|
June 30
|
|
Sept. 30
|
|
Dec. 31
|
|
Operating revenue
|
$
|
80,677
|
|
|
$
|
89,319
|
|
|
$
|
94,427
|
|
|
$
|
113,107
|
|
|
Loss from operations
|
$
|
(172,150
|
)
|
|
$
|
(174,656
|
)
|
|
$
|
(72,128
|
)
|
|
$
|
(90,234
|
)
|
|
Net loss
|
$
|
(188,784
|
)
|
|
$
|
(195,761
|
)
|
|
$
|
(89,635
|
)
|
|
$
|
(116,406
|
)
|
|
Basic loss per share
|
$
|
(33.89
|
)
|
|
$
|
(35.05
|
)
|
|
$
|
(16.01
|
)
|
|
$
|
(20.76
|
)
|
|
Diluted loss per share
|
$
|
(33.89
|
)
|
|
$
|
(35.05
|
)
|
|
$
|
(16.01
|
)
|
|
$
|
(20.76
|
)
|
|
|
|
|
|
|
|
|
|
|
Write-down of oil and gas properties
|
$
|
129,204
|
|
|
$
|
118,649
|
|
|
$
|
36,484
|
|
|
$
|
73,094
|
|
|
Restructuring fees
|
$
|
953
|
|
|
$
|
9,436
|
|
|
$
|
5,784
|
|
|
$
|
13,424
|
|
|
Other operational expenses (1)
|
$
|
12,527
|
|
|
$
|
27,680
|
|
|
$
|
9,059
|
|
|
$
|
6,187
|
|
|
Reorganization items
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10,947
|
|
(1) See
Note 19 – Other Operational Expenses
for additional details.
NOTE 24 — NEW YORK STOCK EXCHANGE COMPLIANCE
On May 17, 2016, we were notified by the New York Stock Exchange (the “NYSE”) that our average global market capitalization had been less than
$50 million
over a consecutive
30
trading-day period at the same time that our stockholders’ equity was less than
$50 million
, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual. On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE, and on August 4, 2016, the NYSE accepted the Plan. All of our quarterly updates to the business plan were accepted by the NYSE. Since March 1, 2017, the first day of trading subsequent to the effective date of the Company’s plan of reorganization, the Successor Company has maintained a market capitalization above
$50 million
.
On August 24, 2017, we were notified by the NYSE that we are back in compliance with their continued listing standards as a result of the Company’s consistent positive performance with respect to the original business plan submission and the achievement of compliance with the average global market capitalization and stockholders’ equity listing requirements over the past two quarters. In accordance with the NYSE’s Listed Company Manual, we will be subject to a 12-month follow up period within which the Company will be reviewed to ensure that the Company does not fall below any of the NYSE’s continued listing standards.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The following is a description of the meanings of some of the oil and gas industry terms used in this Form 10-K. The revisions and additions to the definition section in Rule 4-10(a) of Regulation S-X contained in the SEC’s rule, “Modernization of Oil and Gas Reporting”, are included. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the rule.
Bbl
. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf
. One billion cubic feet of gas.
Boe
. Barrels of oil equivalent. Determined using the ratio of six mcf of natural gas to one barrel of crude oil.
Btu.
British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Development well
. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well
. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Field.
An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms
structural feature
and
stratigraphic condition
are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
Gross acreage or gross wells
. The total acres or wells, as the case may be, in which a working interest is owned.
Liquidity.
The ability to obtain cash quickly either through the conversion of assets or the incurrence of liabilities.
MBbls
. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf
. One thousand cubic feet of gas.
Mcfe
. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.
MMBbls
. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe
. One million barrels of oil equivalent. Determined using the ratio of six mcf of natural gas to one barrel of crude oil.
MMBtu.
One million Btus.
MMcf
. One million cubic feet of gas.
Net acres or net wells
. The sum of the fractional working interests owned in gross acres or gross wells expressed as whole numbers and fractions of whole numbers.
Primary term lease.
An oil and gas property with no existing production, in which Stone has a specific time frame to establish production without losing the rights to explore the property.
Productive well
. A well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed reserves
. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction technology equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved oil and natural gas reserves
. Those quantities of oil and 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 hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Reasonable certainty is defined as “much more likely to be achieved than not”.
Proved undeveloped reserves (“PUDs”)
. 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.
Standardized measure of discounted future net cash flows.
The standardized measure represents value-based information about an enterprise’s proved oil and natural gas reserves based on estimates of future cash flows, including income taxes, from production of proved reserves assuming continuation of certain economic and operating conditions. Future cash flows are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period.
Undeveloped acreage
. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas regardless of whether such acreage contains proved reserves.
Working interest
. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.