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EX-99.1 - EXHIBIT 99.1 - STONE ENERGY CORPsgy123116ex991.htm
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EX-21.1 - EXHIBIT 21.1 - STONE ENERGY CORPsgy123116ex211.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
or
[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission File Number: 1-12074
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
 
Delaware
 
 
 
72-1235413
(State or other jurisdiction of incorporation or organization)
 
 
 
(I.R.S. Employer Identification No.)
625 E. Kaliste Saloom Road
Lafayette, Louisiana
 
 
 
70508
(Address of principal executive offices)
 
 
 
(Zip Code)
Registrant’s telephone number, including area code: (337) 237-0410
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
 
Name of each exchange on which registered
Common Stock, Par Value $.01 Per Share
 
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  [   ] Yes  [X] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  [   ] Yes  [X] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   [X] Yes    [   ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   [X] Yes [   ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ]
 
Accelerated filer [X]
 
Non-accelerated filer  [   ]
(Do not check if a smaller reporting company)
 
Smaller reporting company [   ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).   [   ] Yes   [X] No
The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $66.3 million as of June 30, 2016 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).
As of February 23, 2017, the registrant had outstanding 5,679,765 shares of Common Stock, par value $.01 per share.




TABLE OF CONTENTS
 
 
Page No.
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
PART II
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
PART III
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
PART IV
 
 
 
Item 15.
 
 




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 a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. As of December 31, 2016, our estimated proved oil and natural gas reserves were approximately 53 MMBoe or 321 Bcfe. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell all of our Appalachia Properties (as defined in Reorganization and Chapter 11 Proceedings – Purchase and Sale Agreement below). We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia.
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 additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.
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. During the second half of 2014, commodity prices began a substantial decline, which continued throughout 2015 and 2016. In response to that decline and the uncertainty regarding future commodity prices, we adjusted our near-term strategy to focus on maintaining maximum liquidity, which included reductions in capital expenditures in 2016 and the shut-in of our Mary field in Appalachia from September 2015 until late June 2016. In March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives.
Overview
The lower commodity prices from mid-2014 through 2016 resulted in reduced revenue and cash flows and have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of December 31, 2016, we had total indebtedness of $1,427.8 million, including $300 million of 1¾% Senior Convertible Notes due in March 2017 (the "2017 Convertible Notes"), $775 million of 7½% Senior Notes due in 2022 (the "2022 Notes"), $341.5 million outstanding under our bank credit facility and $11.3 million outstanding under our 4.20% Building Loan (the "Building Loan"). Additionally, we had $35.2 million of accrued interest payable on our outstanding indebtedness.
In response to the significant decline in commodity prices, we focused on managing our balance sheet during 2016 to preserve liquidity during this extended low commodity price environment by taking certain steps, including reductions in capital expenditures and the termination and renegotiation of various contracts, reductions in workforce and reductions in discretionary expenditures. Additionally, in March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We engaged in negotiations with financial advisors for the holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and with our banks regarding an amendment to our bank credit facility.
On March 10, 2016, we borrowed $385 million under our bank credit facility, which at the time, represented substantially all of the undrawn amount on our $500 million bank credit facility. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base

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deficiency. In June 2016, however, we entered into Amendment No. 3 (the "June Amendment") to our bank credit facility which, among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. In addition, the June Amendment required that we maintain minimum liquidity (as defined in the June Amendment) of $125.0 million through January 15, 2017, imposed limitations on capital expenditures from June to December 2016 and provided for anti-hoarding cash provisions for amounts in excess of $50.0 million beginning after December 10, 2016. Upon execution of the June Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time. In December 2016, we reached agreements with the banks to extend the effective date of the anti-hoarding cash provisions to December 15, 2016.
In June 2016, we terminated our deep water drilling rig contract with Ensco for total consideration of $20 million. Additionally, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, whereby we elected to resume production at the Mary field, which had been shut-in since September 2015. In August 2016, we paid $7.5 million for the early terminations of an Appalachian drilling rig contract and a contract with an offshore vessel provider.
As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipated that the minimum liquidity requirement and other restrictions under the June Amendment would prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes on March 1, 2017. As a result of these conditions, continued decreases in commodity prices and the significant level of our indebtedness, we continued to work with our financial and legal advisors throughout 2016 to structure a plan of reorganization to improve our financial position and liquidity and allow for growth and long-term success. On December 14, 2016, we filed for bankruptcy.
Reorganization and Chapter 11 Proceedings

On December 14, 2016, 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 for reorganization (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 Company's plan of reorganization (the "Plan"), as modified by the Confirmation Order. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all.
During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" in accordance with applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by the Debtors, allowing the Company to operate its business in the ordinary course throughout the bankruptcy process. The first day motions included, among other things, a cash collateral motion, a motion maintaining the Company's existing cash management system and motions making various vendor payments, wage payments and tax payments in the ordinary course of business. Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements.
Restructuring Support Agreement. Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors entered into a restructuring support agreement (the "Original RSA") with certain holders of the 2017 Convertible Notes and the 2022 Notes (collectively, the "Notes" and the holders thereof, the "Noteholders") to support a restructuring on the terms of the Plan. On November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan, including 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 "Credit Facility"), and the Noteholders. On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into an Amended and Restated Restructuring Support Agreement (the "A&R RSA") that amended, superseded and restated in its entirety the Original RSA. In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan. The solicitation period ended on December 16, 2016 and (i) of the 94.24% of Noteholders in aggregate outstanding principal amount that voted, 99.95% voted in favor of the Plan and .05% voted to reject the Plan, and (ii) 100% of the Banks voted to accept the Plan.
Additionally, on December 16, 2016, an ad hoc group of certain of the Company's stockholders (the "Stockholder Ad Hoc Group") filed a motion (the "Equity Committee Motion") to appoint an official committee of equity security holders in connection with the Debtors' Chapter 11 proceedings. On December 21, 2016, the Company reached a settlement agreement with the Stockholder Ad Hoc Group (the "Settlement") and on December 28, 2016, the Plan was amended.

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Pursuant to the terms of the Plan, as amended, to be consistent with the terms of the A&R RSA and the term sheet annexed to the A&R RSA (the "Term Sheet") and as amended pursuant to the Settlement, the Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022 (the "Second Lien Notes"). The Banks will receive their respective pro rata share of commitments and obligations under an amended credit agreement (the "Amended Credit Facility") on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA (as defined below). Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the new warrants, which may be exercised any time prior to the fourth anniversary of the Plan's effective date, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed. Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan. Assuming implementation of the Plan, Stone expects that it will eliminate approximately $1.2 billion in principal amount of outstanding debt.
Purchase and Sale Agreement. 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"), and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the A&R RSA. The consummation of the Plan is subject to customary conditions and other requirements, as well as the sale by Stone of the Appalachia Properties, 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 Corporation, through its wholly-owned subsidiary EQT Production Company ("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. Under the EQT PSA, the sale of the Appalachia Properties has an effective date of June 1, 2016. The EQT PSA contains customary representations, warranties and covenants. At the close of the sale of the Appalachia Properties, the Tug Hill PSA will terminate, and the Company will use a portion of the cash consideration received to pay Tug Hill a break-up fee of $10.8 million. On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions.

For additional information on the bankruptcy proceedings, the A&R RSA, the Tug Hill PSA and the EQT PSA, see Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Operational Overview
Gulf of Mexico Basin
Our GOM Basin properties accounted for approximately 66% of our estimated proved oil and natural gas reserves at December 31, 2016 on a volume equivalent basis. 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

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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 new drill wells, which require less capital and time than new deep water 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 approximately 56% of our estimated proved oil and natural gas reserves at December 31, 2016 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 approximately 10% of our estimated proved oil and natural gas reserves at December 31, 2016 on a volume equivalent basis.
Appalachia
In response to low commodity prices and high midstream costs in the area, we shut in our Mary field from September 2015 until late June 2016 and suspended completion operations on 25 drilled wells in Appalachia until commodity prices and margin improvements could be realized. In late June 2016, we entered into an interim Appalachian midstream contract that provided near-term relief by permitting us to resume profitable production and positive cash flow at the Mary field.
In connection with our restructuring efforts, we determined that a sale of the Appalachia Properties would be a beneficial way to maximize value for all stakeholders. On February 9, 2017, we entered into the EQT PSA, and expect to close on the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of our estimated proved oil and natural gas reserves on a volume equivalent basis. Upon closing, we will no longer have operations or assets in Appalachia. See Reorganization and Chapter 11 ProceedingsPurchase and Sale Agreement above.
Business Development
In prior years, the business development effort was focused on providing Stone with exposure to new or unproven plays that could add significant value to the Company if successful. Given the uncertainty regarding future commodity prices, we have only minimal capital allocated for onshore exploration projects or new venture opportunities.
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 68% and 10%, respectively, of our oil and natural gas revenue generated during the year ended December 31, 2016. 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 other 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

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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 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 issued its final well control regulations, effective July 2016, though some requirements of the rule have delayed compliance deadlines. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for blowout preventers ("BOPs"), well design, well control casing, cementing, real-time monitoring and subsea containment. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real-time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. Separately, BOEM proposed new rules in April 2016 that would update existing air emissions requirements relating to offshore oil and natural gas activity on federal OCS waters including in the Central Gulf of Mexico. BOEM regulates these air emissions in connection with its review of exploration and development plans, and right-of-use and right-of-way applications. The proposed rule would bolster existing air emission reporting 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. 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, the BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.
Additionally, on July 14, 2016, BOEM issued a new Notice to Lessees ("NTL"), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurance by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) “Self-Insurance” letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) “Proposal” letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) “Order” letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a “tailored plan” for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for “sole liability” properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan).

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We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are 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, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan we submitted to BOEM may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. 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 new 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.

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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, the BOEM, the BSEE, the 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 the BOEM, the BSEE, the 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.
Waste handling.  The Resource Conservation and Recovery Act (the "RCRA") and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address 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 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. Any such change could result in an increase in our costs to manage and dispose of 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 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"), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for

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neighboring landowners and 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 (the "OPA") and regulations adopted pursuant thereto impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the OCS. The OPA subjects owners of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages. Although defenses exist to the liability imposed by the OPA, they are limited. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of the Interior may increase this amount up to $150 million in certain situations. In addition, the BOEM has finalized rules that raise OPA’s damages liability cap from $75 million to $133.65 million. We cannot predict at this time whether the OPA will be amended further 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 could be liable for costs and damages, which could be material to our results of operations and financial position.
Climate Change.  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 federal Clean Air Act ("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.
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.
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 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 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.

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At this time, we have not yet developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on our operations.
Water discharges.  The federal Water Pollution Control Act (the "Clean Water Act") and analogous state laws, impose restrictions and strict controls with respect to the monitoring and discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or an analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
Air emissions.  The CAA and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources, as well as the emission of other pollutants that the agency has determined pose a threat to the public health and welfare.
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 for our operations that have the potential to affect state air quality, 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.
Endangered Species. Executive Order 13158, issued in May 2000, directs federal agencies to safeguard existing Marine Protected Areas ("MPAs") in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses. Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). 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. Certain flora and fauna that have been officially classified as "threatened" or "endangered" are protected by the Endangered Species Act ("ESA"). This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. We conduct operations on 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.
Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within designated protected areas, wilderness or wetlands. These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.
We have made, and will continue to make, expenditures in our effort to comply with environmental laws and regulations. We do not believe that compliance with applicable environmental laws and regulations will have a material adverse impact on us. However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards and, thus, we cannot give any assurance that we will not be adversely affected in the future.
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. 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

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date, we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

Employees
On February 23, 2017, we had 241 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 and Nominating and Governance Committee Charters, which have been approved by our board of directors. Copies of these documents are also available free of charge by writing 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 June 9, 2016.
Information related to the Bankruptcy Petitions is available at a website administered by our claims agent, Epiq Systems, at http://dm.epiq11.com/StoneEnergy.
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:
expected results from risk-weighted drilling success;
estimates of our future oil and natural gas production, including estimates of any increases in oil and natural gas production;
planned capital expenditures and the availability of capital resources to fund capital expenditures;
our outlook on oil and natural gas prices;
estimates of our oil and natural gas reserves;
any estimates of future earnings growth;
the impact of political and regulatory developments;
our outlook on the resolution of pending litigation and government inquiry;
estimates of the impact of new accounting pronouncements on earnings in future periods;
our future financial condition or results of operations and our future revenues and expenses;
the outcome of restructuring efforts and asset sales;
the amount, nature and timing of any potential acquisition or divestiture transactions;
any expected results or benefits associated with our acquisitions;
our access to capital and our anticipated liquidity;
estimates of future income taxes; and
our business strategy and other plans and objectives for future operations.

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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:
our ability to consummate the Plan in accordance with the terms of the A&R RSA, or alternative restructuring transaction;
risks attendant to the bankruptcy process, including the effects thereof on the Company’s business and on the interests of various constituents;
the length of time that the Company might be required to operate in bankruptcy and the continued availability of operating capital during the pendency of such proceedings;
risks associated with third party motions in any bankruptcy case, which may interfere with the ability to consummate the Plan;
potential adverse effects of bankruptcy proceedings and emergence from bankruptcy on the Company’s liquidity or results of operations;
increased costs to execute a reorganization;
effects of bankruptcy proceedings and emergence from bankruptcy on the market price of the Company’s common stock and on the Company’s ability to access the capital markets;
our ability to maintain our listing on the New York Stock Exchange (the "NYSE");
commodity price volatility, including further or sustained declines in the prices we receive for our oil and natural gas production;
domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;
the availability of capital on economic terms to fund our operations, capital expenditures, acquisitions and other obligations;
our future level of indebtedness, liquidity, compliance with debt covenants and our ability to continue as a going concern;
our future financial condition, results of operations, revenues, cash flows and expenses;
the potential need to sell certain assets or raise additional capital;
our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by BOEM;
declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our current bank credit facility or future bank credit facilities and impairments;
our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
the impact of a financial crisis on our business operations, financial condition and ability to raise capital;
the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
third-party interruption of sales to market;
inflation;
lack of availability and cost of goods and services;
market conditions relating to potential acquisition and divestiture transactions;
regulatory and environmental risks associated with drilling and production activities;
our ability to establish operations or production on our acreage prior to the expiration of related leaseholds;
availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;
competition in the oil and gas industry;
our inability to retain and attract key personnel;
drilling and other operating risks, including the consequences of a catastrophic event;
unsuccessful exploration and development drilling activities;
hurricanes and other weather conditions;
availability, cost and adequacy of insurance coverage;
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;
uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and
other risks described in this Form 10-K.
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

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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 Chapter 11 Proceedings
We will be subject to the risks and uncertainties associated with the Chapter 11 proceedings.
As a consequence of our filing for relief under Chapter 11 of the Bankruptcy Code, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, will be subject to the risks and uncertainties associated with bankruptcy. These risks include the following:
our ability to execute and consummate the Plan or another plan of reorganization with respect to the Chapter 11 proceedings;
the high costs of bankruptcy proceedings and related fees;
our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;
our ability to maintain contracts that are critical to our operations;
our ability to execute our business plan in the current depressed commodity price environment;
the ability to attract, motivate and retain key employees;
the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
the ability of third parties to seek and obtain court approval to convert the Chapter 11 proceedings to Chapter 7 proceedings; and
the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans.

As of December 31, 2016, we had total indebtedness of $1,427 million. Our 2017 Convertible Notes mature on March 1, 2017, and the majority of our other outstanding indebtedness will mature within the next six years. While we anticipate substantially all of our $1,427 million of indebtedness will be discharged upon emergence from Chapter 11 bankruptcy, there is no assurance that the effectiveness of the Plan will occur on February 28, 2017 as expected, or at all.
These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 proceedings that may be inconsistent with our plans.
Upon emergence from bankruptcy, our historical financial information may not be indicative of our future financial performance.
Our capital structure will be significantly altered under the Plan. Under fresh start reporting rules that may apply to us upon the effective date of the Plan (or any alternative plan of reorganization), our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

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The pursuit of the A&R RSA has consumed, and the Chapter 11 proceedings will continue to consume, a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.
Although the Plan is designed to minimize the length of our Chapter 11 proceedings, it is impossible to predict with certainty the amount of time that we may spend in bankruptcy. The Chapter 11 proceedings will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 proceedings are protracted.
During the pendency of the Chapter 11 proceedings, our employees will face considerable distraction and uncertainty, and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.
Trading in our securities is highly speculative and poses substantial risks. Under the Plan, following effectiveness of the Plan, the holders of our existing common stock will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants, which interests could be further diluted by the warrants and the management incentive plan contemplated by the Plan.
The Plan, as contemplated in the A&R RSA, provides that upon the Company's emergence from Chapter 11, Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes and that the holders of the existing common stock of the Company will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. Issuances of common stock (or securities convertible into or exercisable for common stock) under the management incentive plan and any exercises of the warrants for shares of common stock will dilute the voting power of the outstanding common stock and may adversely affect the trading price of such common stock.
Upon emergence from bankruptcy, the composition of our board of directors will change significantly.
Under the Plan, the composition of our board of directors will change significantly. Upon emergence, the board will be made up of seven directors selected by the Noteholders, one of which will be our Chief Executive Officer. Accordingly, six of our seven board members will be new to the Company. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
Assuming the Plan were effective as of the date hereof, it is estimated that two bondholders who currently hold a majority of the Notes would own a majority 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.
The Plan and any other plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our Plan may be unsuccessful in its execution.
The Plan and any other plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our business and will reflect 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 consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a

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continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.
In addition, the Plan and any other plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve 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 any plan of reorganization we may implement 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 any plan of reorganization.
We may be subject to claims that will not be discharged in our Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.
The Bankruptcy Code provides that the confirmation of a Chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a Chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.
Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.
Even if the Plan or any other Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.
Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.
Our ability to continue as a going concern in the long-term is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern in the long-term, even if the Plan is consummated.
Transfers or issuances of our equity, before or in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We had net operating loss carryforwards of approximately $599 million as of December 31, 2016. We believe that our consolidated group will generate additional net operating losses for the 2017 tax year. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce our U.S. federal income tax liability is subject to certain requirements and restrictions. If we experience an "ownership change", as defined in section 382 of the Internal Revenue Code, our ability to use our pre-emergence net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an "ownership change", the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Even if the net operating loss carryforwards are subject to limitation under Section 382, the net operating losses can be further reduced by the amount of discharge of indebtedness arising in a Chapter 11 case under Section 108 of the Internal Revenue Code.
We requested that the Bankruptcy Court approve restrictions on certain transfers of our stock to limit the risk of an "ownership change" prior to our restructuring in our Chapter 11 proceedings. Following the implementation of our Plan, it is likely that an "ownership change" will be deemed to occur and our net operating losses will nonetheless be subject to annual limitation.

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Business Risks
Oil and natural gas prices are volatile. Significant declines in commodity prices have adversely affected, and 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. The significant decline in oil and natural gas prices in the second half of 2014 continuing throughout 2015 and 2016 has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. If commodity prices remain suppressed or continue to decline in the future, it will likely have material adverse effects on our reserves and 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. For example, in response to low commodity prices and the high cost of midstream gathering, processing, and marketing, we shut in production at our Mary field in Appalachia from September 1, 2015 until June 2016. 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. For example, during the period January 1, 2013 through December 31, 2016, the West Texas Intermediate ("WTI") crude oil price per Bbl ranged from a low of $26.21 to a high of $110.53, and the New York Mercantile Exchange ("NYMEX") natural gas price per MMBtu ranged from a low of $1.64 to a high of $6.15. The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:
changes in the supply of and demand for oil and natural gas;
market uncertainty;
level of consumer product demands;
hurricanes and other weather conditions;
domestic and foreign governmental regulations and taxes;
price and availability of alternative fuels;
political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa;
actions by the Organization of Petroleum Exporting Countries;
U.S. and foreign supply of oil and natural gas;
price of oil and natural gas imports; and
overall domestic and foreign economic conditions.
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, including the Amended Credit Facility and the indenture for the Second Lien Notes, 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:
incurring additional debt;
paying dividends on stock, redeeming stock or redeeming subordinated debt;
making investments;
creating liens on our assets;

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selling assets;
guaranteeing other indebtedness;
entering into agreements that restrict dividends from our subsidiary to us;
merging, consolidating or transferring all or substantially all of our assets; and
entering into transactions with affiliates.
Our level of indebtedness, and the covenants contained in current and future agreements governing our debt, including the Amended Credit Facility and the indenture for the Second Lien Notes, could have important consequences on our operations, including:
making it more difficult for us to satisfy our obligations under the indentures or other debt and increasing the risk that we may default on our debt obligations;
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;
limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
detracting from our ability to successfully withstand a downturn in our business or the economy generally;
placing us at a competitive disadvantage against other less leveraged competitors; and
making us vulnerable to increases in interest rates because debt under our bank credit facility is at variable rates.
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 our indentures, 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.
We filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code on December 14, 2016 pursuant to the Plan. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million (subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017), subject to decrease under certain circumstances. See Bank Credit Facility below. There can be no assurance that we will emerge from bankruptcy on February 28, 2017 as expected. See Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources for additional information on our current credit facility and the Amended Credit Facility effective upon emergence from Chapter 11 bankruptcy.

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Regulatory requirements and permitting procedures imposed by the BOEM and BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.
Subsequent to the Deepwater Horizon incident in the GOM in April 2010, the BOEM issued a series of NTLs imposing regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These regulatory requirements include the following:
the Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;
the Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;
the Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and
the Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system ("SEMS") to reduce human and organizational errors as root causes of work-related accidents and offshore spills, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, establish procedures to provide all personnel with "stop work" authority, and to have their SEMS periodically audited by an independent third party auditor approved by the BSEE.
Since the adoption of these new regulatory requirements, the BOEM has been taking longer to review and approve permits for new wells than was common prior to the Deepwater Horizon incident. The rules also increase the cost of preparing each permit application and increase the cost of each new well, particularly for wells drilled in deeper waters of the OCS. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the GOM if we fail to comply with the BOEM’s NTLs or other regulatory requirements. Additional federal action is likely. For example, in April 2016, BSEE issued its final well control regulations, effective July 2016, though some requirements of the rule have delayed compliance deadlines. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for blowout preventers ("BOPs"), well design, well control casing, cementing, real-time monitoring and subsea containment. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real-time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. Separately, BOEM proposed new rules in April 2016 that would update existing air emissions requirements relating to offshore oil and natural gas activity on federal OCS waters including in the Central Gulf of Mexico. BOEM regulates these air emissions in connection with its review of exploration and development plans, and right-of-use and right-of-way applications. The proposed rule would bolster existing air emission reporting 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. 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, the BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.
New guidelines recently issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the outer continental shelf 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 and many other operators have been able to obtain an exemption from most bonding obligations based on 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 $118 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.  A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.

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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 discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) Self-Insurance letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) Proposal letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) Order letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a tailored plan for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for sole liability properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan).
We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are 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, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. 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 new 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.
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. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities 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

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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.
Following the disposition of the Appalachia Properties, our production, revenue and cash flow from operating activities will be derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Following the disposition of the Appalachia Properties, our production, revenue and cash flow from operating activities will be 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 will mean that some or all of the properties could be affected should the region experience:
severe weather, such as hurricanes and other adverse weather conditions;
delays or decreases in production, the availability of equipment, facilities or services;
delays or decreases in the availability or capacity to transport, gather or process production; and/or
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.

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.
Following the sale of the Appalachia Properties, our production will be 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.
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 $825 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 coverage limit of up to $600 million per occurrence. Additionally, we currently maintain $150 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 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.

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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 declined significantly during the second half of 2014 continuing throughout 2015 and 2016. We recorded non-cash ceiling test write-downs of approximately $351 million, $1,362 million and $357 million for the years ended December 31, 2014, 2015 and 2016, respectively. 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.
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; 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. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. 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. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances, and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.

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The closing market price of our common stock has recently declined significantly.  On April 29 and May 17, 2016, we were notified by the NYSE that our common stock was not in compliance with NYSE listing standards. If we are unable to cure the market capitalization deficiency, our common stock could be delisted from the NYSE or trading could be suspended.
Our common stock is currently listed on the NYSE. In order for our common stock to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per share during a consecutive 30 trading-day period. In addition to the minimum average closing price criteria, we are considered to be below compliance if our average market capitalization over a consecutive 30 day-trading period is less than $50 million and, at the same time, our stockholders’ equity is less than $50 million.
On April 29, 2016, we were notified by the NYSE that the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. On May 17, 2016, we were notified by 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.
On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock in order to increase the per share trading price of our common stock in order to regain compliance with the NYSE’s minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement. We remain non-compliant with the $50 million average market capitalization and stockholders’ equity requirements.
On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE. After our submission of the business plan, the NYSE had 45 calendar days to review the plan to determine whether we have made reasonable demonstration of our ability to come into conformity with the relevant standards within the 18-month period. The NYSE accepted the plan on August 4, 2016 and will continue to review the Company on a quarterly basis for compliance with the plan. Upon acceptance of the plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50 million, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting. If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances causing the variance, and determine whether such variance warrants commencement of suspension and delisting procedures. Additionally, under Section 802.01D of the NYSE Listed Company Manual, if a company that is below a continued listing standard files or announces an intent to file for relief under Chapter 11 of the Bankruptcy Code, the company is subject to immediate suspension and delisting. However, if we are profitable or have positive cash flow, or if we are demonstrably in sound financial health despite the bankruptcy proceedings, the NYSE may evaluate our plan in light of the filing without immediate suspension and delisting of our common stock. To date, and throughout the Chapter 11 filing period, we have continued to trade on the NYSE.
On September 20, 2016, we submitted our quarterly update to the business plan for the second of quarter 2016, and the NYSE notified us that it accepted the quarterly update on September 22, 2016. On December 22, 2016, we submitted our quarterly update to the business plan for the third quarter of 2016, and the NYSE notified us that it accepted the quarterly update on January 5, 2017.
In addition to potentially commencing suspension or delisting procedures in respect of our common stock if we fail to meet the material aspects of the plan or any of the quarterly milestones or if we file for bankruptcy and do not have positive cash flow or are not in sound financial health, our common stock could be delisted pursuant to Section 802.01 of the NYSE Listed Company Manual if the trading price of our common stock on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per share, and our common stock could also be delisted pursuant to Section 802.01 if our average market capitalization over a consecutive 30 day-trading period is less than $15 million. In these events, we would not have an opportunity to cure the market capitalization deficiency, and our shares would be delisted immediately and suspended from trading on the NYSE.
The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing, and attract and retain personnel by means of equity compensation, would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price of our common stock.

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Additional issuances of equity securities by us would dilute the ownership of our existing stockholders and could reduce our earnings per share.
The Plan provides, among other things, that upon emergence from bankruptcy, our existing common stock will be cancelled and (i) the Noteholders will receive their pro rata share of 95% of the common stock in reorganized Stone and (ii) existing holders of common stock in Stone will receive their pro rata share of 5% of the common stock in reorganized Stone, plus warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan.
Additionally, we may issue equity in the future in connection with capital raisings, debt exchanges, acquisitions, strategic transactions or for other purposes. To the extent we issue substantial additional equity securities, the ownership of our existing stockholders would be diluted, and our earnings per share could be reduced.
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. Following the sale of the Appalachia Properties, our existing operations will be exclusively in the GOM. 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.

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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, 2016 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 the amount and timing of actual development expenditures, the rate and timing of production and changes in governmental regulations or taxes. At December 31, 2016, approximately 20% of our estimated proved reserves (by volume) were undeveloped. 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.
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 within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage may expire. We have leases on 18,777 gross acres (9,970 net) that could potentially expire during fiscal year 2017. See Item 2. Properties – Productive Well and Acreage Data.
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 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 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:
unexpected drilling conditions;
pressure or irregularities in formations;
equipment failures or accidents;
hurricanes and other weather conditions;

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shortages in experienced labor; and
shortages or delays in the delivery of equipment.
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 are also 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.
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 shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. 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 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 and suspension of operations.
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.

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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.
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 the 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.

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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 of directors rather than pursue non-negotiated takeover attempts. Our Certificate of Incorporation authorizes our board of directors 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 of directors 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 of directors 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. See Item 3. Legal Proceedings. 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. We may also become involved in litigation over certain issues related to the Plan, including the proposed treatment of certain claims thereunder. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods.
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.  Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s 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,

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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.
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.
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 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 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. At this time, we have not yet developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on 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 Dodd-Frank 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

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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 are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.
Hedging transactions may limit our potential gains or become ineffective.
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, without prior approval of our board of directors, generally not more than 60% of our estimated production quantities may be hedged for any given year. These arrangements may include futures contracts on the NYMEX or the Intercontinental Exchange. 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:
our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
the counterparties to our futures contracts fail to perform the contracts;
a sudden, unexpected event materially impacts oil or natural gas prices; or
we are unable to market our production in a manner contemplated when entering into the hedge contract.
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, 2016, our property portfolio consisted of eight active properties and 68 primary term leases in the GOM Basin, three active properties in the Appalachia region and inactive undeveloped acreage in the Rocky Mountain region. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell the Appalachia Properties. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia. See Item 1. Business – Operational Overview. The properties that we currently operate accounted for 93% of our year-end 2016 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 of directors 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

28


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 - Planning, Marketing & Midstream 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 - Planning, Marketing & Midstream or the reserves committee.
Estimates of our proved reserves at December 31, 2016 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 (approximately 66% of which are located in the GOM and 34% in the Appalachia region) as of December 31, 2016. The 2016 average twelve-month oil and natural gas prices net of differentials were $40.15 per Bbl of oil, $9.46 per Bbl of NGLs and $1.71 per Mcf of natural gas.
Summary of Oil, Natural Gas and NGL Reserves as of
December 31, 2016
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Natural Gas
(MMcf)
 
Oil, Natural
Gas and
NGLs
(MMcfe)
Reserves Category:
 
 
 
 
 
 
 
PROVED
 
 
 
 
 
 
 
Developed
18,269

 
9,255

 
90,741

 
255,884

Undeveloped
5,011

 
1,374

 
26,579

 
64,889

TOTAL PROVED
23,280

 
10,629

 
117,320

 
320,773

At December 31, 2016, we reported estimated proved undeveloped reserves ("PUDs") of 64.9 Bcfe, which accounted for 20% of our total estimated proved oil and natural gas reserves. This figure ties to a projected four new wells (60.2 Bcfe) and one sidetrack well from an existing wellbore (4.7 Bcfe). The timetable for drilling this sidetrack well is totally dependent on the life of the currently producing zone. After the current zone has been depleted, we would utilize the existing wellbore to sidetrack to the PUD objective. Regarding the remaining four PUD locations, we project three wells to be drilled in 2017 (52.1 Bcfe) and one well in 2018 (8.1 Bcfe). None of these four 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 2016.

29


 
Oil, Natural
Gas and
NGLs
(MMcfe)
 
Future
Development
Costs
(in thousands)
PUDs beginning of year
92,894

 
$
181,954

Revisions of previous estimates
(11,051
)
 
(15,216
)
Conversions to proved developed reserves
(16,954
)
 
(37,766
)
Additional PUDs added

 

PUDs end of year
64,889

 
$
128,972

During 2016, we invested approximately $37.8 million to convert 17.0 Bcfe of PUDs to proved developed reserves in the GOM. As of December 31, 2016, we had no PUDs in the Appalachia region.
The following represents additional information on our significant properties:
 
 
 
 
 
 
December 31, 2016
 
 
 
 
 
 
2016
 
Estimated
 
 
Field Name
 
Location
 
Production
(MMcfe)
 
Proved Reserves
(MMcfe)
 
Nature of
Interest
Pompano (1)
 
GOM Deep Water
 
32,629

 
142,302

 
Working
Mary (2)
 
Appalachia
 
20,850

 
101,227

 
Working
Mississippi Canyon Block 109
 
GOM Deep Water
 
6,386

 
37,641

 
Working
Bayou Hebert
 
Gulf Coast Deep Gas
 
3,916

 
14,064

 
Working
Main Pass Block 288
 
GOM Shelf
 
3,554

 
10,533

 
Working
Ship Shoal Block 113
 
GOM Shelf
 
4,668

 
6,821

 
Working
Heather (2)
 
Appalachia
 
7,169

 
5,931

 
Working
(1)
Production volumes include the Pompano, Cardona and Amethyst fields, all of which tie back to the Pompano platform. Estimated proved reserves include the Pompano and Cardona fields. The Amethyst well was shut-in during late April 2016 to allow for a technical evaluation. Intervention operations were unsuccessful and there were no estimated proved reserves booked at December 31, 2016. We expect to begin temporary abandonment operations on the well in late February 2017, and we will evaluate the well for potential sidetrack operations in the second half of 2017. The estimated proved reserves associated with the Amethyst well at year-end 2015 were approximately 78,870 MMcfe.
(2)
At December 31, 2015, all of our Mary field reserves were removed from proved reserves due to the effect of reduced commodity prices. In late June 2016, we entered into an interim Appalachian midstream contract whereby we elected to resume production at the Mary field.
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.

30


Acquisition, Production and Drilling Activity
Acquisition and Development Costs.  The following table sets forth certain information regarding the costs incurred in our acquisition, development and exploratory activities in the United States and Canada during the periods indicated.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(In thousands)
Acquisition costs, net of sales of unevaluated properties
$
3,425

 
$
(17,020
)
 
$
51,590

Exploratory costs
20,059

 
112,936

 
289,890

Development costs (1)
102,665

 
266,982

 
438,334

Subtotal
126,149

 
362,898

 
779,814

Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements
47,866

 
68,410

 
76,363

Total additions to oil and gas properties, net
$
174,015

 
$
431,308

 
$
856,177

(1)
Includes capitalized asset retirement costs of ($4,461), ($43,901) and ($20,305) for the years ended December 31, 2016, 2015 and 2014, 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.
 
Year Ended December 31,
 
2016
 
2015
 
2014
Production:
 
 
 
 
 
Oil (MBbls)
6,308

 
5,991

 
5,568

Natural gas (MMcf)
29,441

 
36,457

 
47,426

NGLs (MBbls)
2,183

 
2,401

 
2,114

Oil, natural gas and NGLs (MMcfe)
80,387

 
86,809

 
93,518

Average sales prices:
 
 
 
 
 
Prior to the cash settlement of effective hedging contracts
 
 
 
 
 
Oil (per Bbl)
$
40.82

 
$
46.88

 
$
91.27

Natural gas (per Mcf)
1.80

 
1.90

 
3.67

NGLs (per Bbl)
13.23

 
13.46

 
40.51

Oil, natural gas and NGLs (per Mcfe)
4.22

 
4.40

 
8.21

Including the cash settlement of effective hedging contracts
 
 
 
 
 
Oil (per Bbl)
$
44.59

 
$
69.52

 
$
92.69

Natural gas (per Mcf)
2.19

 
2.29

 
3.51

NGLs (per Bbl)
13.23

 
13.46

 
40.51

Oil, natural gas and NGLs (per Mcfe)
4.66

 
6.13

 
8.21

Expenses (per Mcfe):
 
 
 
 
 
Lease operating expenses (1)
$
0.99

 
$
1.15

 
$
1.89

Transportation, processing and gathering expenses
0.35

 
0.68

 
0.69

(1)
Includes oil and gas operating costs and major maintenance expense and excludes production taxes.

31


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, 2016.
 
Year Ended December 31,
FIELD: Pompano (1)
2016
 
2015
 
2014
Production:
 
 
 
 
 
Oil (MBbls)
3,858

 
2,994

 
1,311

Natural gas (MMcf)
7,882

 
3,466

 
2,894

NGLs (MBbls)
267

 
245

 
151

Oil, natural gas and NGLs (MMcfe)
32,629

 
22,902

 
11,666

Average sales prices:
 
 
 
 
 
Oil (per Bbl)
$
41.86

 
$
49.18

 
$
92.53

Natural gas (per Mcf)
2.15

 
2.17

 
3.10

NGLs (per Bbl)
12.46

 
15.28

 
41.27

Oil, natural gas and NGLs (per Mcfe)
5.57

 
6.92

 
11.70

Expenses (per Mcfe):
 
 
 
 
 
Lease operating expenses (2)
$
0.78

 
$
0.91

 
$
2.75

Transportation, processing and gathering expenses
0.10

 
0.07

 
0.13

(1)
Includes the Pompano, Cardona and Amethyst fields, all of which tie back to the Pompano platform.
(2)
Includes oil and gas operating costs and major maintenance expense and excludes production taxes.
 
Year Ended December 31,
FIELD: Mary (1)
2016
 
2015
 
2014
Production:
 
 
 
 
 
Oil (MBbls)
278

 
464

 
525

Natural gas (MMcf)
10,012

 
16,764

 
17,974

NGLs (MBbls)
1,528

 
1,583

 
1,247

Oil, natural gas and NGLs (MMcfe)
20,850

 
29,050

 
28,605

Average sales prices:
 
 
 
 
 
Oil (per Bbl)
$
32.91

 
$
26.35

 
$
51.72

Natural gas (per Mcf)
1.61

 
1.77

 
3.55

NGLs (per Bbl)
11.99

 
11.04

 
38.86

Oil, natural gas and NGLs (per Mcfe)
2.09

 
2.05

 
4.88

Expenses (per Mcfe):
 
 
 
 
 
Lease operating expenses (2)
$
0.47

 
$
0.48

 
$
0.55

Transportation, processing and gathering expenses
0.86

 
1.35

 
1.50

(1)
The Mary field was shut in from September 2015 through June 2016.
(2)
Includes oil and gas operating costs and major maintenance expense and excludes production taxes.


32


Drilling Activity.  The following table sets forth our drilling activity for the periods indicated.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive

 

 
2

 
0.25

 
5

 
4.31

Dry

 

 
2

 
0.42

 
2

 
0.90

Development Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive
1

 
0.65

 
7

 
5.81

 
38

 
33.35

Dry

 

 

 

 

 

Productive Well and Acreage Data.  The following table sets forth certain statistics regarding the number of productive wells as of December 31, 2016.
 
Gross
 
Net
Productive Wells:
 
 
 
Oil (1):
 
 
 
Deep Water
48

 
43

Deep Gas

 

Conventional Shelf
27

 
27

Appalachia

 

 
75

 
70

Gas:
 
 
 
Deep Water
1

 
1

Deep Gas
4

 
1

Conventional Shelf
6

 
5

Appalachia
138

 
98

 
149

 
105

Total productive wells
224

 
175

 
 
 
 
 The following table sets forth certain statistics regarding developed and undeveloped acres as of December 31, 2016.
 
Gross
 
Net
Developed Acres:
 
 
 
Deep Water
97,920

 
61,907

Deep Gas
24,729

 
1,702

Conventional Shelf
72,657

 
50,334

Appalachia
48,822

 
40,084

Other
8,356

 
2,642

 
252,484

 
156,669

Undeveloped Acres (2):
 
 
 
Deep Water
325,440

 
206,376

Deep Gas
6,062

 
2,924

Conventional Shelf
5,132

 
5,113

Appalachia
55,999

 
43,689

Other
4,309

 
1,104

 
396,942

 
259,206

Total developed and undeveloped acres
649,426

 
415,875


33


(1) 5 gross wells each have dual completions.
(2) Leases covering approximately 5% of our undeveloped gross acreage will expire in 2017, 36% in 2018, 21% in 2019, 12% in 2020, 5% in 2021, 8% in 2022, and 7% in 2023.

As of December 31, 2016, none of our PUDs were assigned to locations that are currently scheduled to be drilled after lease expiration.
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. On November 10, 2016, a decision dismissing a Jefferson Parish Coastal Zone Management ("CZM") test case failure to exhaust administrative remedies was reversed. Defendants in the test case are seeking appellate review. Shortly after Stone filed a suggestion of bankruptcy in December 2016, Jefferson Parish dismissed two of its three CZM suits against Stone without prejudice to refiling.
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. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 CZM suits filed by the Plaquemines Parish. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit.  Shortly after Stone filed a suggestion of bankruptcy in December 2016, Plaquemines Parish dismissed its CZM suit against Stone without prejudice to refiling.
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, is now complete. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.
On February 4, 2016, ICO Marcellus I, LLC ("ICO") and B&R Holdings, Inc. ("B&R") filed a lawsuit against Stone in Wetzel County, West Virginia, alleging that Stone breached the applicable joint venture agreement and joint operating agreement between the parties. On November 17, 2016, the lawsuit was dismissed based upon the parties’ resolution of all claims. Stone made a cash payment to and was assigned certain interests from ICO and B&R as part of the settlement.

34


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.

Chapter 11 Proceedings
On December 14, 2016, the Debtors filed Bankruptcy Petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. The Plan in our Chapter 11 proceedings provides for the treatment of pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 cases. On February 15, 2017, the Bankruptcy Court entered an order confirming the Company's plan of reorganization. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all. For additional information on the bankruptcy proceedings, see Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.

35


PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Since July 9, 1993, our common stock has been listed on the NYSE under the symbol "SGY." The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock. All share prices reflect the 1-for-10 reverse stock split with respect to our common stock which we completed on June 10, 2016 in order to increase the per share trading price of our common stock in order to regain compliance with the NYSE's minimum share price requirement.
 
High
 
Low
2015
 
 
 
First Quarter
$
189.80

 
$
120.70

Second Quarter
196.50

 
123.30

Third Quarter
125.00

 
37.40

Fourth Quarter
98.40

 
30.60

2016
 
 
 
First Quarter
$
46.60

 
$
6.80

Second Quarter
13.50

 
2.70

Third Quarter
25.50

 
8.42

Fourth Quarter
12.50

 
3.69

2017
 
 
 
First Quarter (through February 21, 2017)
$
9.95

 
$
6.25

On February 21, 2017, the last reported sales price of our common stock on the New York Stock Exchange Composite Tape was $6.62 per share. As of that date, there were 336 holders of record of our common stock.
Dividend Restrictions
In the past, we have not paid cash dividends on our common stock, and we do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and development of our business. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indentures executed in connection with our 2017 Convertible Notes and our 2022 Notes. In addition, our bank credit facility contains provisions that prohibit the payment of dividends. We expect that the Amended Credit Facility and the indenture for the Second Lien Notes also will contain limitations or prohibitions on the payment of dividends.

36


Issuer Purchases of Equity Securities
On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock or granting of stock awards. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the fourth quarter of 2016:
Period
 
Total Number
of Shares
Purchased (1)
 
Average Price
Paid per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs (2)
 
Approximate Dollar
Value of Shares that
May Yet be Purchased
Under the Plans or
Programs
October 1 – October 31, 2016
 
804

 
$
4.10

 
 
 
November 1 – November 30, 2016
 
1,619

 
4.03

 
 
 
December 1 – December 31, 2016
 
 
 
 
 
 
 
2,423

 
$
4.05

 
 
$
92,928,632

(1)
Amount includes shares of our common stock withheld from employees and nonemployee directors upon the vesting of restricted stock or granting of stock awards in order to satisfy the required tax withholding obligations.
(2)
There were no repurchases of our common stock under our share repurchase program during the fourth quarter of 2016.

Equity Compensation Plan Information
Please refer to Item 12 of this Form 10-K for information concerning securities authorized under our equity compensation plan.

37


Stock Performance Graph
As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:
1.
$100 was invested in the Company’s common stock, the Standard & Poor’s 500 Stock Index ("S&P 500 Index") and the Peer Group (as defined below) on December 30, 2011 at $26.38 per share for the Company’s common stock and at the closing price of the stocks comprising the S&P 500 Index and the Peer Group, respectively, on such date.
2.
Peer Group investment is weighted based upon the market capitalization of each individual company within the Peer Group at the beginning of the period.
3.
Dividends are reinvested on the ex-dividend dates.
a2016123110_chart-44048.jpg
  Measurement Period
  (Fiscal Year Covered)
 
SGY
 
2016 Peer
Group
 
S&P 500
Index
12/31/2012
 
77.79

 
91.93

 
116.00

12/31/2013
 
131.12

 
121.45

 
153.57

12/31/2014
 
63.99

 
81.23

 
174.60

12/31/2015
 
16.26

 
48.42

 
177.01

12/31/2016
 
2.71

 
68.01

 
198.18

The companies that comprised our Peer Group in 2016 were: Cabot Oil & Gas Corporation, Callon Petroleum Company, Carrizo Oil & Gas, Inc., Cimarex Energy Company, Comstock Resources, Inc., Contango Oil & Gas Company, Denbury Resources Inc., Energy XXI Ltd., Exco Resources Inc., Newfield Exploration Company, PDC Energy, PetroQuest Energy, Inc., Range Resources Corporation, SandRidge Energy, Inc., SM Energy Company, Swift Energy Company, Ultra Petroleum Corporation, W&T Offshore, Inc. and Whiting Petroleum Corporation. The 2016 Peer Group was the same as our 2015 peer group.
The information in this Form 10-K appearing under the heading "Stock Performance Graph" is being "furnished" pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be "soliciting material" or "filed" with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.

38


ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2016. This information is derived from our consolidated financial statements and the notes thereto. Certain prior year amounts have been reclassified to conform to current year presentation. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
Income Statement Data:
(In thousands, except per share amounts)
Operating revenue:
 
 
 
 
 
 
 
 
 
Oil production
$
281,246

 
$
416,497

 
$
516,104

 
$
715,104

 
$
761,304

Natural gas production
64,601

 
83,509

 
166,494

 
190,580

 
134,739

Natural gas liquids production
28,888

 
32,322

 
85,642

 
60,687

 
48,498

Other operational income
2,657

 
4,369

 
7,951

 
7,808

 
3,520

Derivative income, net

 
7,952

 
19,351

 

 
3,428

Total operating revenue
377,392

 
544,649

 
795,542

 
974,179

 
951,489

Operating expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
79,650

 
100,139

 
176,495

 
201,153

 
215,003

Transportation, processing, gathering expenses
27,760

 
58,847

 
64,951

 
42,172

 
21,782

Production taxes
3,148

 
6,877

 
12,151

 
15,029

 
10,015

Depreciation, depletion and amortization
220,079

 
281,688

 
340,006

 
350,574

 
344,365

Write-down of oil and gas properties
357,431

 
1,362,447

 
351,192

 

 

Accretion expense
40,229

 
25,988

 
28,411

 
33,575

 
33,331

Salaries, general and administrative expenses
58,928

 
69,384

 
66,451

 
59,524

 
54,648

Franchise tax settlement

 

 

 
12,590

 

Incentive compensation expense
13,475

 
2,242

 
10,361

 
15,340

 
8,113

Restructuring fees
29,597

 

 

 

 

Other operational expenses
55,453

 
2,360

 
862

 
151

 
267

Derivative expense, net
810

 

 

 
2,090

 

Total operating expenses
886,560

 
1,909,972

 
1,050,880

 
732,198

 
687,524

Income (loss) from operations
(509,168
)
 
(1,365,323
)
 
(255,338
)
 
241,981

 
263,965

Other (income) expenses:
 
 
 
 
 
 
 
 
 
Interest expense
64,458

 
43,928

 
38,855

 
32,837

 
30,375

Interest income
(550
)
 
(580
)
 
(574
)
 
(1,695
)
 
(600
)
Other income
(1,439
)
 
(1,783
)
 
(2,332
)
 
(2,799
)
 
(1,805
)
Other expense
596

 
434

 
274

 

 

Loss on early extinguishment of debt

 

 

 
27,279

 
1,972

Reorganization items
10,947

 

 

 

 

Total other expenses
74,012

 
41,999

 
36,223

 
55,622

 
29,942

Income (loss) before income taxes
(583,180
)
 
(1,407,322
)
 
(291,561
)
 
186,359

 
234,023

Income tax provision (benefit)
7,406

 
(316,407
)
 
(102,018
)
 
68,725

 
84,597

Net income (loss)
$
(590,586
)
 
$
(1,090,915
)
 
$
(189,543
)
 
$
117,634

 
$
149,426

Basic earnings (loss) per share
$
(105.63
)
 
$
(197.45
)
 
$
(35.95
)
 
$
23.58

 
$
30.31

Diluted earnings (loss) per share
$
(105.63
)
 
$
(197.45
)
 
$
(35.95
)
 
$
23.56

 
$
30.28

Cash dividends declared per share

 

 

 

 

Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
78,588

 
$
247,474

 
$
401,141

 
$
594,205

 
$
509,749

Net cash used in investing activities
(238,172
)
 
(321,290
)
 
(872,587
)
 
(623,036
)
 
(568,688
)
Net cash provided by financing activities
339,415

 
10,161

 
215,446

 
80,594

 
300,014

Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Working capital (deficit)
$
132,409

 
$
(8,803
)
 
$
226,805

 
$
181,255

 
$
300,348

Oil and gas properties, net
811,514

 
1,211,986

 
2,414,002

 
2,619,696

 
2,182,095

Total assets
1,139,483

 
1,410,169

 
3,009,857

 
3,238,117

 
2,750,987

Long-term debt, less current portion (1)
352,376

 
1,060,955

 
1,032,281

 
1,016,645

 
888,682

Stockholders’ equity
(637,282
)
 
(39,789
)
 
1,101,603

 
970,286

 
872,133

(1) Reduction in long-term debt is due to the reclassification of the Company's 2017 Convertible Notes and 2022 Notes to liabilities subject to compromise.

39


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our financial position and results of operations for each of the years in the three-year period ended December 31, 2016. Our consolidated financial statements and the notes thereto, which are found elsewhere in this Form 10-K, contain detailed information that should be referred to in conjunction with the following discussion. See Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data – Note 1.
Executive Overview
We are 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 GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell all of our Appalachia Properties. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia. See Item 1. Business – Operational Overview.
2016 Overview
The lower commodity prices from mid-2014 through 2016 resulted in reduced revenue and cash flows and have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of December 31, 2016, we had total indebtedness of $1,427.8 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $341.5 million outstanding under our bank credit facility and $11.3 million outstanding under our Building Loan. In response to the significant decline in commodity prices, we focused on managing our balance sheet during 2016 to preserve liquidity during this extended low commodity price environment by taking certain steps, including reductions in capital expenditures and the termination and renegotiation of various contracts, reductions in workforce and reductions in discretionary expenditures. Additionally, in March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We engaged in negotiations with financial advisors for the holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and with our banks regarding an amendment to our bank credit facility.
On March 10, 2016, we borrowed $385 million under our bank credit facility, which at the time, represented substantially all of the undrawn amount on our $500 million bank credit facility. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. In June 2016, however, we entered into the June Amendment to our bank credit facility, which among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. Upon execution of the June Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time.
In June 2016, we terminated our deep water drilling rig contract with Ensco for total consideration of $20 million. Additionally, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, whereby we elected to resume production at the Mary field, which had been shut-in since September 2015. In August 2016, we paid $7.5 million for the early terminations of an Appalachian drilling rig contract and a contract with an offshore vessel provider.
Production from our deep water Amethyst well was shut-in in April 2016 to allow for a technical evaluation.  During the first week of November, we initiated acid stimulation work and intermittently flowed the well during the month of November at a rate of 10 – 15 million cubic feet of gas per day, while observing and evaluating the well’s performance. On November 30, 2016, we performed a routine shut-in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak. Intervention operations were unsuccessful. There were no estimated proved reserve quantities booked at December 31, 2016 for the Amethyst well. We expect to begin temporary abandonment operations on the well in late February 2017, and we will evaluate the well for potential sidetrack operations in the second half of 2017. As of December 31, 2015, Amethyst represented approximately 23% and 26% of our estimated proved reserves quantities and standardized measure of discounted future net cash flows, respectively. 
As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipated that the minimum liquidity requirement and other restrictions under the June Amendment would prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of

40


2016 as well as the subsequent maturity of our 2017 Convertible Notes on March 1, 2017. As a result of these conditions, continued decreases in commodity prices and the significant level of our indebtedness, we continued to work with our financial and legal advisors throughout 2016 to structure a plan of reorganization to improve our financial position and liquidity and allow for growth and long-term success. See Liquidity and Capital Resources.
Reorganization and Chapter 11 Proceedings

On December 14, 2016, the Debtors filed the Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" in accordance with applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by the Debtors, allowing the Company to operate its business in the ordinary course throughout the bankruptcy process. The first day motions included, among other things, a cash collateral motion, a motion maintaining the Company's existing cash management system and motions making various vendor payments, wage payments and tax payments in the ordinary course of business. Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all.
Restructuring Support Agreement
Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors entered into the Original RSA with the Noteholders to support a restructuring on the terms of the Plan. On November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan. The solicitation period ended on December 16, 2016 and (i) of the 94.24% of Noteholders in aggregate outstanding principal amount that voted, 99.95% voted in favor of the Plan and .05% voted to reject the Plan, and (ii) 100% of the Banks voted to accept the Plan.
On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA that amended, superseded and restated in its entirety the Original RSA. In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan. Additionally, on December 16, 2016, the Stockholder Ad Hoc Group filed the Equity Committee Motion to appoint an official committee of equity security holders in connection with the Debtors' Chapter 11 proceedings. On December 21, 2016, the Company reached a settlement agreement with the Stockholder Ad Hoc Group and on December 28, 2016, the Plan was amended.
Upon emergence from bankruptcy by the Debtors, and pursuant to the terms of the Plan, as amended, Noteholders, Banks and other interest holders will receive treatment under the Plan, summarized as follows:
The Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes.

Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. The warrants will have an exercise price equal to a total equity value of the reorganized Company that implies a 100% recovery of outstanding principal to the Company’s noteholders plus accrued interest through the Plan’s effective date less the face amount of the Second Lien Notes and the Prepetition Notes Cash (as defined in the Plan). The warrants may be exercised any time prior to the fourth anniversary of the Plan’s effective date, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

Banks signatory to the A&R RSA will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA.

All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed.


41


Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan. Assuming implementation of the Plan, Stone expects that it will eliminate approximately $1.2 billion in principal amount of outstanding debt.
Purchase and Sale Agreement
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 sale of the Appalachia Properties to Tug Hill, pursuant to the terms of the Tug Hill PSA, and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the A&R RSA. The consummation of the Plan is subject to customary conditions and other requirements, as well as the sale by Stone of the Appalachia Properties 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 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 the EQT PSA with EQT, reflecting the terms of the prevailing bid. Under the EQT PSA, the sale of the Appalachia Properties has an effective date of June 1, 2016. The EQT PSA contains customary representations, warranties and covenants. From and after the closing of the sale of the Appalachia Properties, the Company and EQT, respectively, have agreed to indemnify each other and their respective affiliates against certain losses resulting from any breach of their representations, warranties or covenants contained in the EQT PSA, subject to certain customary limitations and survival periods. Additionally, from and after closing of the sale of the Appalachia Properties, the Company has agreed to indemnify EQT for certain identified retained liabilities related to the Appalachia Properties, subject to certain survival periods, and EQT has agreed to indemnify the Company for certain assumed obligations related to the Appalachia Properties. The EQT PSA may be terminated, subject to certain exceptions, (i) upon mutual written consent, (ii) if the closing has not occurred by March 1, 2017, (iii) for certain material breaches of representations and warranties or covenants that remain uncured and (iv) upon the occurrence of certain other events specified in the EQT PSA.

At the close of the sale of the Appalachia Properties, the Tug Hill PSA will terminate, and the Company will use a portion of the cash consideration received to pay Tug Hill a break-up fee of $10.8 million. On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions. Upon closing of the sale, Stone will no longer have operations or assets in Appalachia. The Appalachia Properties accounted for approximately 34% of our estimated proved oil and natural gas reserves on a volume equivalent basis at December 31, 2016.


42


2017 Outlook
Upon emergence from bankruptcy, we expect that we will eliminate approximately $1.2 billion in principal amount of outstanding debt, resulting in remaining debt outstanding of approximately $236 million, consisting of the $225 million of Second Lien Notes and $11 million outstanding under the Building Loan. We expect our cash and cash equivalents to total approximately $150 million at emergence. Additionally, we will have $75 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Facility. Although our capital expenditure budget for 2017 has not yet been approved by the board of directors and is dependent on the outcome of our Chapter 11 proceedings and the related reorganization of the Company, the financial projections prepared in connection with our restructuring efforts included estimated preliminary capital expenditures of approximately $200 million for 2017. The projected capital expenditures of $200 million included approximately $86 million of plugging and abandonment costs. In early 2017, we reinstated development drilling operations using a platform rig at Pompano. While management believes the Company's expected cash flows from operating activities, cash on hand and availability under the Amended Credit Facility will be adequate to meet the operating needs of the post-reorganized Company, there are no assurances that our Chapter 11 Plan, which was confirmed by the Bankruptcy Court on February 15, 2017, will become effective on February 28, 2017 as expected, or at all. Our projected 2017 capital expenditures exclude material acquisitions and capitalized salaries, general and administrative ("SG&A") expenses and interest.
Historically, we have funded our capital expenditures primarily through cash on hand, expected cash flows from operating activities and borrowings under the bank credit facility. Although we have no current plans to access the public or private equity or debt markets for purposes of capital, we may consider such funding sources to provide additional capital.
In January and February 2017, we entered into various fixed-price swaps and put contracts for a portion of our expected 2017 and 2018 oil production from the Gulf Coast Basin (see note 7 to the consolidated financial statements). In an effort to mitigate some commodity price risk, we continue to monitor the marketplace for additional hedges. Pursuant to requirements under the Plan, we expect to hedge approximately 50% of our estimated production from estimated proved producing reserves for each of 2017 and 2018.

Known Trends and Uncertainties
Fresh Start Accounting – We may be required to adopt fresh start accounting upon emergence (the "fresh start reporting date") from Chapter 11. The guidance in fresh start accounting results in the allocation of the reorganization value to individual assets based on their estimated fair values. The enterprise value of the equity of the Company at emergence will be based on several assumptions and inputs contemplated in the Plan that are subject to significant uncertainties. We currently cannot estimate the potential impact of fresh start accounting on our consolidated financial statements upon emergence from bankruptcy, although we would expect to recognize material adjustments upon implementation of fresh start accounting guidance.
Write-down of Oil and Gas Properties – We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and 2016, resulting in reduced revenue and cash flows and causing us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties. For the years ended December 31, 2014, 2015 and 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million and $357 million, respectively.
If NYMEX commodity prices remain at current levels (approximately $54.00 per Bbl of oil and $2.55 per MMBtu of natural gas), we would expect an increase in the twelve-month average price used in estimating the present value of estimated future net cash flows of our proved reserves. However, we expect that the pricing differences between the trailing twelve-month average pricing assumption required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward looking prices required by fresh start accounting to estimate the fair value of our oil and natural gas properties on the fresh start reporting date may result in an additional write-down of our oil and gas properties during the first quarter of 2017. Additionally, significant evaluations or impairments of unevaluated costs or other well performance-related revisions affecting proved reserve quantities could cause us to recognize further write-downs.
Bank Credit Facility Throughout 2016, the level of our indebtedness and the depressed commodity price environment presented challenges as they related to our ability to comply with the covenants in the current agreements governing our indebtedness. In connection with our restructuring and pursuant to the Plan, we expect to eliminate approximately $1.2 billion in principal amount of outstanding debt upon emergence from bankruptcy, however, there can be no assurance that we will emerge from bankruptcy on February 28, 2017 as expected, or at all.
Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. The borrowing base under our bank

43


credit facility as of February 23, 2017 was $360 million, a reduction from the borrowing base of $500 million as of April 12, 2016. Upon emergence from bankruptcy, the borrowing base would be further reduced under the Amended Credit Facility to $200 million, subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. See Liquidity and Capital Resources. Continued low commodity prices or further declines in commodity prices could have a further adverse impact on the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.
BOEM Financial Assurance Requirements – 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 and many other operators have been able to obtain an exemption from most bonding obligations based on 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. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565 million. 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 $118 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.
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 discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) Self-Insurance letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) Proposal letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) Order letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a tailored plan for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for sole liability properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan).
We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are 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, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan we submitted to BOEM may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. 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 new 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.

44


Although the surety companies have not historically required collateral from us to back our surety bonds, we recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide additional cash collateral on existing and/or new surety bonds required by BOEM to satisfy financial assurance requirements. We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds to comply with supplemental bonding requirements of the BOEM. This need to obtain additional surety bonds, or some other form of financial assurances, could impact our liquidity. 

Hurricanes – Since a large portion of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible increases to and/or acceleration of plugging and abandonment costs, all of which could also affect our ability to remain in compliance with the covenants under our current bank credit facility.
Deep Water Operations We are currently operating two significant properties in the deep water of the GOM and engage in deep water drilling operations. Operations in the deep water involve high operational risks. Despite technological advances over the last several years, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant losses on our statement of operations as well as going concern issues.
Liquidity and Capital Resources
Overview
The lower commodity prices from mid-2014 through 2016 resulted in reduced revenue and cash flows and have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of December 31, 2016, our cash and cash equivalents totaled approximately $191 million, and we had total indebtedness of $1,427.8 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $341.5 million outstanding under our bank credit facility and $11.3 million outstanding under our Building Loan. Additionally, we had $35.2 million of accrued interest payable on our outstanding indebtedness.
In response to the significant decline in commodity prices, we focused on managing our balance sheet during 2016 to preserve liquidity during this extended low commodity price environment by taking certain steps, including reductions in capital expenditures and the termination and renegotiation of various contracts, reductions in workforce and reductions in discretionary expenditures. On June 24, 2016, our deep water drilling rig contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. To further reduce capital expenditures for 2016, we elected to temporarily stack the Pompano platform drilling rig in place. In addition, during the third quarter of 2016 we terminated an offshore vessel contract and Appalachian rig contract.
In June 2016, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, which had been shut-in since September 2015. The interim agreement provided near-term relief by permitting Stone to resume profitable production and positive cash flow at the Mary field. The initial term of the interim agreement was through August 31, 2016 and it continues on a month to month basis until the sale of the Appalachia Properties is completed. See "Purchase and Sale Agreement" above.

On April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. At the time, we elected to pay the deficiency in six equal installments, making the first two payments of $29.2 million in May and June 2016. On June 14, 2016, we entered into the June Amendment to, among other things, increase the borrowing base to $360 million, and on that date, we repaid $56.8 million in borrowings, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. See "Bank Credit Facility" below.
We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017. Additionally, we had an interest obligation under our 2022 Notes of approximately $29.2 million due on November 15, 2016 (see "Senior Notes" below). The indenture governing the 2022 Notes provides a 30-day grace period that extended the latest date for making this cash interest payment to December 15, 2016 before an event of default occurs under the indenture. Although we had sufficient liquidity to make the interest payment by the due date, we elected to not make this interest payment and utilized the 30-day grace period provided by the indenture before entering into the Chapter 11 proceedings.

45


As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipated that the minimum liquidity requirement and other restrictions under the June Amendment would prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes on March 1, 2017. As a result of these conditions, continued decreases in commodity prices and the significant level of our indebtedness, we continued to work with our financial and legal advisors throughout 2016 to structure a plan of reorganization to improve our financial position and liquidity and allow for growth and long-term success.
In connection with our restructuring efforts, we determined that a sale of the Appalachia Properties would be a beneficial way to maximize value for all stakeholders. On February 9, 2017, we entered into the EQT PSA to sell all of our Appalachia Properties for cash consideration of $527 million, subject to customary purchase price adjustments. On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions.
On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA, pursuant to which (1) the Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes, and (2) the Banks will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million, subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. See Bank Credit Facility below.
The Debtors filed the Bankruptcy Petitions on December 14, 2016, and on February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy. While we anticipate most of our $1,427 million of indebtedness will be discharged upon emergence from Chapter 11 bankruptcy, there is no assurance that the effectiveness of the Plan will occur on February 28, 2017, or at all. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company's obligations under all of its outstanding debt instruments, resulting in the principal and interest due thereunder immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions, and the creditors' rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
Although our capital expenditure budget for 2017 has not yet been approved by the board of directors and is dependent on the outcome of our Chapter 11 proceedings and the related reorganization of the Company, the financial projections prepared in connection with our restructuring efforts included estimated preliminary capital expenditures of approximately $200 million for 2017. The projected capital expenditures of $200 million included approximately $86 million of plugging and abandonment costs. In early 2017, we reinstated development drilling operations using a platform rig at Pompano. We expect that cash flows from operating activities, cash on hand and availability under the Amended Credit Facility for 2017 will be adequate to meet the operating needs of the reorganized Company; however, there are no assurances that we will emerge from bankruptcy on February 28, 2017 as expected, or at all.
Historically, we have been able to obtain an exemption from supplemental bonding requirements on our offshore leases for abandonment obligations based on 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. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.
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 discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength.

46


We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are 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, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan we submitted to BOEM may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. 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.
Although the surety companies have not historically required collateral from us to back our surety bonds, we recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide additional cash collateral on existing and/or new surety bonds required by BOEM to satisfy financial assurance requirements. This need to obtain additional surety bonds or some other form of financial assurance, could impact our liquidity. See Known Trends and Uncertainties.
Indebtedness
Bank Credit Facility – On June 24, 2014, we entered into a revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019 and is guaranteed by Stone Offshore. The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility 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 in any calendar year, to have the borrowing base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the 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 the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. At that time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016.
On June 14, 2016, we entered into the June Amendment to the bank credit facility to (i) increase the borrowing base to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ended September 30, 2016, 9.50 to 1 for the fiscal quarter ended December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the June Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures from June through December 2016, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the June Amendment, we repaid $56.8 million in borrowings under the credit facility, bringing total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation under the credit facility at that time. In December 2016, we reached agreements with the banks to extend the effective date of the anti-hoarding cash provisions to December 15, 2016. On February 23, 2017, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility.
The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Low commodity prices and negative price differentials have had a material adverse impact on the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. Continued low commodity

47


prices or further declines in commodity prices will likely have a further material adverse impact on the value of our estimated proved reserves.
Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. In addition to the covenants discussed above, the bank credit facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the Credit Facility, for the preceding four quarterly periods of not less than 2.5 to 1. As of December 31, 2016, our Consolidated Funded Debt to consolidated EBITDA ratio was 6.90 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 3.24 to 1. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.
As discussed above, on February 15, 2017, the Bankruptcy Court entered an order confirming the Company's Plan, and the Debtors expect to emerge from bankruptcy on February 28, 2017. Upon emergence, the Banks will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million, subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. Additionally, (i) the margin for loans at the LIBOR rate will be increased to a range of 3.00% to 4.00% and (ii) our ability to pay cash dividends, prepay other indebtedness and make investments has been curtailed. Under the Amended Credit Facility we must maintain the following financial covenants: (i) a ratio of consolidated funded indebtedness to EBITDA of not greater than 3.50 to 1.00 to 2.50 to 1.00 (depending on the quarter tested); (ii) a ratio of EBITDA to net interest expense of less than 2.75 to 1.00; and (iii) liquidity (including undrawn amounts under the Amended Credit Facility) equal to 20% of the then-current borrowing base. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 95% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. The Amended Credit Facility will be a four-year facility.
Senior Notes – At December 31, 2016, our senior notes consisted of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. The 2017 Convertible Notes are due on March 1, 2017. As discussed above, on February 15, 2017, the Bankruptcy Court entered an order confirming the Company's Plan, and the Debtors expect to emerge from bankruptcy on February 28, 2017. Upon emergence, the $300 million and $775 million of debt related to the 2017 Convertible Notes and the 2022 Notes, respectively, will be cancelled and the Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes.
Second Lien Notes – The Second Lien Notes to be issued under the Plan will be secured by second-priority liens (junior in priority to the liens securing the obligations under the Amended Credit Facility) on the same assets securing the obligations under the Amended Credit Facility. They will bear interest at a rate of 7.5% per annum, payable in cash, with a maturity of May 31, 2022. The Second Lien Notes will be redeemable at any time, subject to the following make whole amounts: (1) if the Company prepays the Second Lien Notes prior to the third anniversary of issuance, the prepayment amount shall be at par, plus accrued interest, plus a make whole payment equal to the spread over a comparable treasury note plus 50 basis points, (2) if the Company prepays the Second Lien Notes after the third anniversary, but prior to the fifth anniversary, of issuance, the prepayment amount shall be at 105.625% of par, plus accrued interest and (3) if the Company prepays the Second Lien Notes on or after the fifth anniversary of issuance, the prepayment amount shall be at par plus accrued interest.
Building Loan – On November 20, 2015, we entered into the Building Loan, maturing on December 20, 2030. We received $11.8 million in cash, net of debt issuance costs related to the Building Loan. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments commencing on December 20, 2015. 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. As of December 31, 2016, our EBITDA to Net Interest Expense ratio was 3.24 to 1. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. There will be no changes to the terms of the Building Loan pursuant to the Plan.
Upon emergence from bankruptcy, we expect that we will eliminate approximately $1.2 billion in principal amount of outstanding debt, resulting in remaining debt outstanding of approximately $236 million, consisting of the $225 million of Second Lien Notes and $11 million outstanding under the Building Loan.

48


Cash Flow and Working Capital
Net cash provided by operating activities totaled $78.6 million during the year ended December 31, 2016 compared to $247.5 million and $401.1 million during the years ended December 31, 2015 and 2014, respectively. The decrease from 2015 to 2016 was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices, the decline in natural gas and NGL production volumes, restructuring fees, rig subsidy and stacking expenses and drilling rig and offshore vessel contract termination fees, partially offset by a decline in lease operating and transportation, processing and gathering ("TP&G") expenses. The decrease from 2014 to 2015 was primarily due to the decline in oil, natural gas and NGL prices, partially offset by a decline in lease operating expenses. See Results of Operations for additional information relative to commodity prices, production and operating expense variances.
Net cash used in investing activities totaled $238.2 million during the year ended December 31, 2016, which primarily represents our investment in oil and gas properties of $238.0 million. Net cash used in investing activities totaled $321.3 million during the year ended December 31, 2015, which primarily represents our investment in oil and gas properties of $522.0 million, offset by $179.5 million of previously restricted proceeds from the sale of oil and gas properties of $22.8 million of proceeds from the sale of oil and gas properties. Net cash used in investing activities totaled $872.6 million during the year ended December 31, 2014, which primarily represents our investment in oil and gas properties of $927.2 million and our investment in fixed and other assets of $10.2 million, offset by unrestricted proceeds from the sale of oil and gas properties of $64.8 million.
Net cash provided by financing activities totaled $339.4 million during the year ended December 31, 2016, which primarily represents $477.0 million in borrowings under our bank credit facility less $135.5 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $10.2 million during the year ended December 31, 2015, which primarily represents $11.8 million of net proceeds from our Building Loan, offset by net payments for share-based compensation of approximately $3.1 million. During the year ended December 31, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $215.4 million during the year ended December 31, 2014, which primarily represents net proceeds from the sale of common stock of approximately $226.0 million, offset by net payments for share-based compensation of approximately $7.2 million and deferred financing costs of approximately $3.4 million associated with our bank credit facility.
We had working capital of $132.4 million at December 31, 2016. The $300 million of 2017 Convertible Notes due on March 1, 2017 are classified as liabilities subject to compromise at December 31, 2016 in our consolidated balance sheet. See Note 2 to the accompanying consolidated financial statements.
Capital Expenditures
During the year ended December 31, 2016, additions to oil and gas property costs of $174.0 million included $3.3 million of lease and property acquisition costs, $21.2 million of capitalized SG&A expenses (inclusive of incentive compensation) and $26.6 million of capitalized interest. These investments were financed with cash flows from operating activities and borrowings under our bank credit facility.
Share Repurchase Program
On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2016, 30,000 shares had been repurchased under this program at a total cost of approximately $7.1 million, or an average price of $235.70 per share (after the effectiveness of the reverse stock split of 1-for-10). No shares were repurchased during the years ended December 31, 2016, 2015 or 2014.
Hedging
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.
Safety Performance
Historically, we have measured our safety performance based on the total recordable incident rate ("TRIR"), which is the number of safety incidents per 200,000 man-hours worked for employees and certain contractors. For 2015, we broadened our safety performance measures, using a new factor called our Health, Safety and Environmental ("HSE") factor. The HSE factor includes not only personal safety as reflected by the TRIR, but also environmental safety, as measured by reported spills of hydrocarbons, and compliance safety, as measured by fines or penalties paid to state or federal regulatory agencies. All onshore safety incidents are reported to the Occupational Safety and Health Administration ("OSHA") and are tracked on OSHA Form

49


301. All offshore safety incidents are reported to the BOEM. Our TRIR is provided to the BOEM as part of a voluntary program for safety monitoring in the GOM. The HSE factor for the years ended December 31, 2016 and 2015 and the TRIR for the year ended December 31, 2014 were as follows:
Year Ended December 31,
 
Safety Performance
 
Safety Goal
2016
 
0.28
 
0.30
2015
 
0.14
 
0.30
2014
 
0.00
 
0.50
Our safety initiative includes formal programs for observation and reporting of at-risk and safe behavior in and away from the work place, employee awards for results and observations, employee participation in training programs and internal safety audits. We have an annual cash incentive compensation plan that includes a safety component based on our annual HSE factor.

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Reorganization Items
The Debtors have incurred and will continue to incur significant costs associated with the reorganization and Chapter 11 process. These costs, which are being expensed as incurred, significantly impact the Company's results of operations. Reorganization items includes professional fees and other expenses incurred in the Chapter 11 Cases, and the write-off of the remaining unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise. For the year ended December 31, 2016, reorganization items totaled $10.9 million. See Note 2 to the accompanying consolidated financial statements for further details.
Results of Operations
2016 Compared to 2015. The following table sets forth certain information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See Item 2. Properties – Oil and Natural Gas Reserves.
 
Year Ended December 31,
 
2016
 
2015
 
Variance
 
% Change
Production:
 
 
 
 
 
 
 
Oil (MBbls)
6,308

 
5,991

 
317

 
5
 %
Natural gas (MMcf)
29,441

 
36,457

 
(7,016
)
 
(19
)%
NGLs (MBbls)
2,183

 
2,401

 
(218
)
 
(9
)%
Oil, natural gas and NGLs (MMcfe)
80,387

 
86,809

 
(6,422
)
 
(7
)%
Revenue data (in thousands): (1)
 
 
 
 
 
 
 
Oil revenue
$
281,246

 
$
416,497

 
$
(135,251
)
 
(32
)%
Natural gas revenue
64,601

 
83,509

 
(18,908
)
 
(23
)%
NGLs revenue
28,888

 
32,322

 
(3,434
)
 
(11
)%
Total oil, natural gas and NGL revenue
$
374,735

 
$
532,328

 
$
(157,593
)
 
(30
)%
Average prices:
 
 
 
 
 
 
 
Prior to the cash settlement of effective hedging contracts
 
 
 
 
 
 
 
Oil (per Bbl)
$
40.82

 
$
46.88

 
$
(6.06
)
 
(13
)%
Natural gas (per Mcf)
1.80

 
1.90

 
(0.10
)
 
(5
)%
NGLs (per Bbl)
13.23

 
13.46

 
(0.23
)
 
(2
)%
Oil, natural gas and NGLs (per Mcfe)
4.22

 
4.40

 
(0.18
)
 
(4
)%
Including the cash settlement of effective hedging contracts
 
 
 
 
 
 
 
Oil (per Bbl)
$
44.59

 
$
69.52

 
$
(24.93
)
 
(36
)%
Natural gas (per Mcf)
2.19

 
2.29

 
(0.10
)
 
(4
)%
NGLs (per Bbl)
13.23

 
13.46

 
(0.23
)
 
(2
)%
Oil, natural gas and NGLs (per Mcfe)
4.66

 
6.13

 
(1.47
)
 
(24
)%
Expenses (per Mcfe):
 
 
 
 
 
 
 
Lease operating expenses
$
0.99

 
$
1.15

 
$
(0.16
)
 
(14
)%
Transportation, processing and gathering expenses
0.35

 
0.68

 
(0.33
)
 
(49
)%
Salaries, general and administrative expenses (2)
0.73

 
0.80

 
(0.07
)
 
(9
)%
DD&A expense on oil and gas properties
2.68

 
3.19

 
(0.51
)
 
(16
)%
Estimated Proved Reserves at December 31:
 
 
 
 
 
 
 
Oil (MBbls)
23,280

 
30,276

 
(6,996
)
 
(23
)%
Natural gas (MMcf)
117,320

 
121,858

 
(4,538
)
 
(4
)%
NGLs (MBbls)
10,629

 
6,458

 
4,171

 
65
 %
Oil, natural gas and NGLs (MMcfe)
320,773

 
342,260

 
(21,487
)
 
(6
)%
(1)
Includes the cash settlement of effective hedging contracts.
(2)
Excludes incentive compensation expense.

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Net Loss.  For the year ended December 31, 2016, we reported a net loss totaling $590.6 million, or $105.63 per share, compared to a net loss for the year ended December 31, 2015 of $1,090.9 million, or $197.45 per share. All per share amounts are on a diluted basis.
We follow the full cost method of accounting for oil and gas properties. During the year ended December 31, 2016, we recognized write-downs of our U.S. and Canadian oil and gas properties totaling $357.4 million. During the year ended December 31, 2015, we recognized write-downs of our U.S. and Canadian oil and gas properties totaling $1,362.4 million. The write-downs did not impact our cash flows from operating activities but did increase net loss and decrease stockholders’ equity.
The variance in annual results was also due to the following components:
Production.  During the year ended December 31, 2016, total production volumes decreased to 80.4 Bcfe compared to 86.8 Bcfe produced during the comparable 2015 period, representing a 7% decrease. Oil production during the year ended December 31, 2016 totaled approximately 6,308 MBbls compared to 5,991 MBbls produced during the year ended December 31, 2015. Natural gas production totaled 29.4 Bcf during the year ended December 31, 2016 compared to 36.5 Bcf produced during the comparable 2015 period. NGL production during the year ended December 31, 2016 totaled approximately 2,183 MBbls compared to 2,401 MBbls produced during the comparable 2015 period.
The decreases in natural gas and NGL production volumes during the year ended December 31, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016. Additionally, in April 2016, production from our deep water Amethyst well was shut in to allow for a technical evaluation.  During the first week of November 2016, we initiated acid stimulation work, and on November 30, 2016, we performed a routine shut in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak. Intervention operations were unsuccessful.
For the year ended December 31, 2016, total production volumes attributable to the Appalachia Properties were approximately 28.3 Bcfe, comprised of 16.1 Bcf of natural gas, 281 MBbls of oil and 1,753 MBbls of NGLs.
Prices.  Prices realized during the year ended December 31, 2016 averaged $44.59 per Bbl of oil, $2.19 per Mcf of natural gas and $13.23 per Bbl of NGLs, or 24% lower, on an Mcfe basis, than 2015 average realized prices of $69.52 per Bbl of oil, $2.29 per Mcf of natural gas and $13.46 per Bbl of NGLs. All unit pricing amounts include the cash settlement of effective hedging contracts.
We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. During the year ended December 31, 2016, effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and increased our average realized oil price by $3.77 per Bbl. During the year ended December 31, 2015, effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and increased our average realized oil price by $22.64 per Bbl.
Revenue.  Oil, natural gas and NGL revenue decreased 30% to $374.7 million for the year ended December 31, 2016 from $532.3 million for the year ended December 31, 2015. Total revenue for the year ended December 31, 2016 was lower primarily due to a 7% decrease in production volumes and a 24% decrease in average realized prices on an equivalent basis from the comparable period of 2015. For the year ended December 31, 2016, total oil, natural gas and NGL revenue attributable to the Appalachia Properties was $56.7 million.
Derivative Income/Expense.  Net derivative expense for the year ended December 31, 2016 totaled $0.8 million, comprised of $0.7 million of income from cash settlements and $1.5 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the year ended December 31, 2015, net derivative income totaled $8.0 million, comprised of $24.4 million of income from cash settlements and $16.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.
Expenses.  Lease operating expenses for the years ended December 31, 2016 and 2015 totaled $79.7 million and $100.1 million, respectively. On a unit of production basis, lease operating expenses were $0.99 per Mcfe and $1.15 per Mcfe for the years ended December 31, 2016 and 2015, respectively. The decrease in lease operating expenses in 2016 was primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. For the year ended December 31, 2016, lease operating expenses attributable to the Appalachia Properties were $11.6 million.
TP&G expenses for the year ended December 31, 2016 totaled $27.8 million, which included a $7.9 million recoupment of prior period expenses against Federal royalties, compared to $58.8 million for the year ended December 31, 2015, or $0.35 per

52


Mcfe and $0.68 per Mcfe, respectively. The decrease in TP&G expenses during the year ended December 31, 2016 was primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016. For the year ended December 31, 2016, TP&G expenses attributable to the Appalachia Properties were $28.1 million.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the year ended December 31, 2016 totaled $215.7 million, or $2.68 per Mcfe, compared to DD&A expense of $277.1 million, or $3.19 per Mcfe, for the year ended December 31, 2015. The decrease in DD&A from 2015 was primarily due to the ceiling test write-downs of our oil and gas properties.
Other operational expenses for the years ended December 31, 2016 and 2015 totaled $55.5 million and $2.4 million, respectively. Included in other operational expenses for the year ended December 31, 2016 are $9.9 million in charges related to the terminations of an Appalachian drilling rig contract and contracts with two GOM vendors, a $20.0 million charge related to the termination of our deep water drilling rig contract with Ensco in June 2016, approximately $17.7 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Appalachian drilling rig and the platform rig at Pompano, and a $6.1 million cumulative foreign currency translation loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, which was reclassified from accumulated other comprehensive income.
For the years ended December 31, 2016 and 2015, SG&A expenses (exclusive of incentive compensation) totaled $58.9 million and $69.4 million, respectively. On a unit of production basis, SG&A expenses were $0.73 per Mcfe and $0.80 per Mcfe for the years ended December 31, 2016 and 2015, respectively. The decrease in SG&A expenses in 2016 was primarily attributable to staff and other cost reductions. SG&A expenses for the year ended December 31, 2015 included $2.1 million of lease termination charges associated with the early termination of an office lease.
For the years ended December 31, 2016 and 2015, incentive compensation expense totaled $13.5 million and $2.2 million, respectively. The 2016 incentive compensation cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Portions of the 2016 incentive cash bonuses replaced amounts previously awarded to employees as stock-based compensation, reflected in SG&A expenses, resulting in higher incentive compensation expense in the year ended December 31, 2016 as compared to the year ended December 31, 2015.
For the year ended December 31, 2016, restructuring fees totaled $29.6 million. These fees, incurred prior to the filing of the Bankruptcy Petitions, related to expenses supporting our restructuring effort including legal and financial advisory costs for Stone, our bank group and our noteholders.
Interest expense for the year ended December 31, 2016 totaled $64.5 million, net of $26.6 million of capitalized interest, compared to interest expense of $43.9 million, net of $41.3 million of capitalized interest, for the year ended December 31, 2015. The increase in interest expense was primarily the result of interest expense associated with the increased borrowings under our bank credit facility and a decrease in the amount of interest capitalized to oil and gas properties.
For the years ended December 31, 2016 and 2015, we recorded an income tax provision (benefit) of $7.4 million and ($316.4) million, respectively. The income tax benefit recorded for the year ended December 31, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 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. The change in the valuation allowance was recorded as an adjustment to income tax expense.

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2015 Compared to 2014. The following table sets forth certain information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See Item 2. Properties – Oil and Natural Gas Reserves.
 
Year Ended December 31,
 
2015
 
2014
 
Variance