STONE ENERGY CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - FORM 8-K - STONE ENERGY CORP	f8k051217eyopinionupdate.htm

Table of Contents

Exhibit 99.1

INDEX TO FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheet as December 31, 2016 and 2015	F-3

Consolidated Statement of Operations for the years ended December 31, 2016, 2015 and 2014	F-4

Consolidated Statement of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014	F-5

Consolidated Statement of Cash Flows for the years ended December 31, 2016, 2015 and 2014	F-6

Consolidated Statement of Changes in Stockholders' Equity for the years ended December 31, 2016, 2015 and 2014	F-7

Notes to Consolidated Financial Statements	F-8

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Stone Energy Corporation as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

Since the date of completion of our audit of the accompanying consolidated financial statements and initial issuance of our report thereon dated February 23, 2017, which report contained an explanatory paragraph regarding the Company’s ability to continue as a going concern, as discussed in Note 3, the Company’s prepackaged plan of reorganization became effective and the Company emerged from bankruptcy on February 28, 2017. Therefore, the conditions that raised substantial doubt about whether the Company will continue as a going concern no longer exist.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Stone Energy Corporation’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 23, 2017

except for Note 3, as to which the date is

May12, 2017

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED BALANCE SHEET

(In thousands of dollars)



	December 31,
Assets	2016		2015
Current assets:
Cash and cash equivalents	$	190,581	$	10,759
Accounts receivable	48,464		48,031
Fair value of derivative contracts	—		38,576
Current income tax receivable	26,086		46,174
Other current assets	10,151		6,881
Total current assets	275,282		150,421
Oil and gas properties, full cost method of accounting:
Proved	9,616,236		9,375,898
Less: accumulated depreciation, depletion and amortization	(9,178,442)		(8,603,955)
Net proved oil and gas properties	437,794		771,943
Unevaluated	373,720		440,043
Other property and equipment, net of accumulated depreciation of $27,418 and $27,424, respectively	26,213		29,289
Other assets, net of accumulated depreciation and amortization of $5,360 and $4,376, respectively	26,474		18,473
Total assets	$	1,139,483	$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	19,981	$	82,207
Undistributed oil and gas proceeds	15,073		5,992
Accrued interest	809		9,022
Asset retirement obligations	88,000		21,291
Current portion of long-term debt	408		—
Other current liabilities	18,602		40,712
Total current liabilities	142,873		159,224
Long-term debt	352,376		1,060,955
Asset retirement obligations	154,019		204,575
Other long-term liabilities	17,315		25,204
Total liabilities not subject to compromise	666,583		1,449,958
Liabilities subject to compromise	1,110,182		—
Total liabilities	1,776,765		1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,610,020 and 5,530,232 shares, respectively	56		55
Treasury stock (1,658 shares, at cost)	(860)		(860)
Additional paid-in capital	1,659,731		1,648,687
Accumulated deficit	(2,296,209)		(1,705,623)
Accumulated other comprehensive income	—		17,952
Total stockholders’ equity	(637,282)		(39,789)
Total liabilities and stockholders’ equity	$	1,139,483	$	1,410,169

The accompanying notes are an integral part of this balance sheet.

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)



	Year Ended December 31,
	2016		2015		2014
Operating revenue:
Oil production	$	281,246	$	416,497	$	516,104
Natural gas production	64,601		83,509		166,494
Natural gas liquids production	28,888		32,322		85,642
Other operational income	2,657		4,369		7,951
Derivative income, net	—		7,952		19,351
Total operating revenue	377,392		544,649		795,542
Operating expenses:
Lease operating expenses	79,650		100,139		176,495
Transportation, processing and gathering expenses	27,760		58,847		64,951
Production taxes	3,148		6,877		12,151
Depreciation, depletion and amortization	220,079		281,688		340,006
Write-down of oil and gas properties	357,431		1,362,447		351,192
Accretion expense	40,229		25,988		28,411
Salaries, general and administrative expenses	58,928		69,384		66,451
Incentive compensation expense	13,475		2,242		10,361
Restructuring fees	29,597		—		—
Other operational expenses	55,453		2,360		862
Derivative expense, net	810		—		—
Total operating expenses	886,560		1,909,972		1,050,880
Loss from operations	(509,168)		(1,365,323)		(255,338)
Other (income) expenses:
Interest expense	64,458		43,928		38,855
Interest income	(550)		(580)		(574)
Other income	(1,439)		(1,783)		(2,332)
Other expense	596		434		274
Reorganization items	10,947		—		—
Total other expenses	74,012		41,999		36,223
Loss before income taxes	(583,180)		(1,407,322)		(291,561)
Provision (benefit) for income taxes:
Current	(5,674)		(44,096)		159
Deferred	13,080		(272,311)		(102,177)
Total income taxes	7,406		(316,407)		(102,018)
Net loss	$	(590,586)	$	(1,090,915)	$	(189,543)
Basic loss per share	$	(105.63)	$	(197.45)	$	(35.95)
Diluted loss per share	$	(105.63)	$	(197.45)	$	(35.95)
Average shares outstanding	5,591		5,525		5,272
Average shares outstanding assuming dilution	5,591		5,525		5,272

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)



	Year Ended December 31,
	2016		2015		2014
Net loss	$	(590,586)	$	(1,090,915)	$	(189,543)
Other comprehensive income (loss), net of tax effect:
Derivatives	(24,025)		(62,758)		88,178
Foreign currency translation	6,073		(2,605)		(2,801)
Comprehensive loss	$	(608,538)	$	(1,156,278)	$	(104,166)

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)



	Year Ended December 31,
	2016		2015		2014
Cash flows from operating activities:
Net loss	$	(590,586)	$	(1,090,915)	$	(189,543)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	220,079		281,688		340,006
Write-down of oil and gas properties	357,431		1,362,447		351,192
Accretion expense	40,229		25,988		28,411
Deferred income tax provision (benefit)	13,080		(272,311)		(102,177)
Settlement of asset retirement obligations	(20,514)		(72,382)		(56,409)
Non-cash stock compensation expense	8,443		12,324		11,325
Excess tax benefits	—		(1,586)		—
Non-cash derivative expense (income)	1,471		16,440		(18,028)
Non-cash interest expense	18,404		17,788		16,661
Non-cash reorganization items	8,332		—		—
Other non-cash expense	6,248		—		—
Change in current income taxes	20,088		(37,377)		158
(Increase) decrease in accounts receivable	(1,412)		43,724		51,611
(Increase) decrease in other current assets	(3,493)		1,767		(6,244)
Decrease in inventory	—		1,304		—
Increase (decrease) in accounts payable	1,026		(14,582)		(3,419)
Increase (decrease) in other current liabilities	9,897		(25,936)		(19,152)
Other	(10,135)		(907)		(3,251)
Net cash provided by operating activities	78,588		247,474		401,141
Cash flows from investing activities:
Investment in oil and gas properties	(237,952)		(522,047)		(927,247)
Proceeds from sale of oil and gas properties, net of expenses	—		22,839		242,914
Investment in fixed and other assets	(1,266)		(1,549)		(10,182)
Change in restricted funds	1,046		179,467		(178,072)
Net cash used in investing activities	(238,172)		(321,290)		(872,587)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000		5,000		—
Repayments of bank borrowings	(135,500)		(5,000)		—
Proceeds from building loan	—		11,770		—
Repayments of building loan	(423)		—		—
Net proceeds from issuance of common stock	—		—		225,999
Deferred financing costs	(900)		(68)		(3,371)
Excess tax benefits	—		1,586		—
Net payments for share-based compensation	(762)		(3,127)		(7,182)
Net cash provided by financing activities	339,415		10,161		215,446
Effect of exchange rate changes on cash	(9)		(74)		(736)
Net change in cash and cash equivalents	179,822		(63,729)		(256,736)
Cash and cash equivalents, beginning of year	10,759		74,488		331,224
Cash and cash equivalents, end of year	$	190,581	$	10,759	$	74,488
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	$	(32,130)	$	(34,394)	$	(14,076)
Cash (paid) refunded for income taxes	25,762		7,212		(1)

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)



	Common Stock		Treasury Stock		Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Total Stockholders’ Equity
Balance, December 31, 2013	$	49	$	(860)	$	1,398,324	$	(425,165)	$	(2,062)	$	970,286
Net loss	—		—		—		(189,543)		—		(189,543)
Adjustment for fair value accounting of derivatives, net of tax	—		—		—		—		88,178		88,178
Adjustment for foreign currency translation, net of tax	—		—		—		—		(2,801)		(2,801)
Exercise of stock options and vesting of restricted stock	—		—		(7,119)		—		—		(7,119)
Amortization of stock compensation expense	—		—		16,709		—		—		16,709
Net tax impact from stock option exercises and restricted stock vesting	—		—		(54)		—		—		(54)
Issuance of common stock	6		—		225,941		—		—		225,947
Balance, December 31, 2014	55		(860)		1,633,801		(614,708)		83,315		1,101,603
Net loss	—		—		—		(1,090,915)		—		(1,090,915)
Adjustment for fair value accounting of derivatives, net of tax	—		—		—		—		(62,758)		(62,758)
Adjustment for foreign currency translation, net of tax	—		—		—		—		(2,605)		(2,605)
Exercise of stock options and vesting of restricted stock	—		—		(2,638)		—		—		(2,638)
Amortization of stock compensation expense	—		—		17,524		—		—		17,524
Balance, December 31, 2015	55		(860)		1,648,687		(1,705,623)		17,952		(39,789)
Net loss	—		—		—		(590,586)		—		(590,586)
Adjustment for fair value accounting of derivatives, net of tax	—		—		—		—		(24,025)		(24,025)
Adjustment for foreign currency translation, net of tax	—		—		—		—		6,073		6,073
Exercise of stock options, vesting of restricted stock and granting of stock awards	1		—		(732)		—		—		(731)
Amortization of stock compensation expense	—		—		11,776		—		—		11,776
Balance, December 31, 2016	$	56	$	(860)	$	1,659,731	$	(2,296,209)	$	—	$	(637,282)

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In thousands of dollars, except per share and price amounts)

NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Operations

Stone Energy Corporation ("Stone" or the "Company") is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We began operating in the Gulf of Mexico (the "GOM") Basin 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 (as defined in Note 2 – Chapter 11 Proceedings 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.

Voluntary Chapter 11 Filing

On December 14, 2016 (the "Petition Date"), the Company and its subsidiaries Stone Energy Offshore, L.L.C. ("Stone Offshore") and Stone Energy Holding, L.L.C. (together with the Company, the "Debtors") filed voluntary petitions (the "Bankruptcy Petitions") in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 ("Chapter 11") of the United States Bankruptcy Code (the "Bankruptcy Code") to pursue a prepackaged plan of reorganization (the "Plan"). For additional details see Note 2 – Chapter 11 Proceedings. During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court in accordance with applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. To assure ordinary course operations, the Debtors sought approval from the Bankruptcy Court for a variety of first day motions, including authority to maintain bank accounts and other customary relief. On February 15, 2017, the Bankruptcy Court entered an order (the "Confirmation Order") confirming the Plan, as modified by the Confirmation Order.

Summary of Significant Accounting Policies

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016 our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

On May 27, 2016, the board of directors of the Company approved a 1-for-10 reverse stock split of the Company's issued and outstanding shares of common stock. The reverse stock split was effective upon the filing and effectiveness of a certificate of amendment to the Company's certificate of incorporation after the market closed on June 10, 2016, and the common stock began trading on a split-adjusted basis when the market opened on June 13, 2016. The effect of the reverse stock split was to combine each 10 shares of outstanding common stock prior to the reverse split into one new share subsequent to the reverse split. The Company's authorized shares of common stock were proportionately decreased in connection with the reverse stock split. Additionally, the overall and per share limitations in the Company’s 2009 Amended and Restated Stock Incentive Plan, as amended from time to time, and outstanding awards thereunder were also proportionately adjusted. The Company retained the current par value of $.01 per share for all shares of common stock.

All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the

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reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares as a result of the reverse split.

Reorganization:

We have applied Accounting Standards Codification ("ASC") 852, "Reorganizations", in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. These liabilities are reported at the amounts the Company expects will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 2 – Chapter 11 Proceedings for more information regarding reorganization items and liabilities subject to compromise.

The Chapter 11 proceedings do not include our former foreign subsidiary Stone Energy Canada, ULC. This subsidiary had no significant activity during 2016, except for the reclassification of approximately $6,081 of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of Stone Energy Canada, ULC. Stone Energy Canada, ULC was dissolved on December 2, 2016.

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ("GAAP") requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization ("DD&A") expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, liabilities subject to compromise versus not subject to compromise, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative contracts, estimates of fair value in business combinations and contingencies.

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2016 and 2015, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

Hybrid Debt Instruments:

In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the "2017 Convertible Notes"). See Note 11 – Debt. On that same day we entered into convertible note hedging transactions which were expected to reduce the potential dilution to our common shareholders upon conversion of the notes. In accordance with ASC 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that reflects our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as interest expense. Additionally, the hedging transactions met the criteria for classification as equity transactions and were recorded as such. The convertible note hedging transactions have since been terminated in connection with our Chapter 11 proceedings.

Cash and Cash Equivalents:

We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.

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Oil and Gas Properties:

We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.

U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. Under the full cost method, all exploratory costs are capitalized, while under the successful efforts method, exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries, while under the successful efforts method, cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.

We amortize our investment in oil and gas properties through DD&A expense using the units of production (the "UOP") method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.

Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows.

Sales of oil and gas properties are accounted for as adjustments to net oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Asset Retirement Obligations:

U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Other Property and Equipment:

Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful lives of 39 years.

Earnings Per Common Share:

Under U.S. GAAP, certain instruments granted in share-based payment transactions are considered participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.

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Production Revenue:

We recognize production revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered or underdelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production.

Income Taxes:

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2014, 2015 and 2016, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.

Derivative Instruments and Hedging Activities:

The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.

Share-Based Compensation:

We record share-based compensation using the grant date fair value of issued stock options, stock awards and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of stock awards and restricted stock is typically determined based on the average of our high and low stock prices on the grant date.

Recently Issued Accounting Standards:

In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

In August 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)". The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it concludes its plans alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 became effective for us on December 15, 2016. The standard impacted our disclosures but had no effect on our financial position, results of operations or cash flows.

In November 2015, the FASB issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes" to simplify the presentation of deferred income taxes. The guidance allows for the presentation of all deferred tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent on the balance sheet. We early adopted ASU 2015-17, on a

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retrospective basis, which affected our disclosures of deferred tax assets and liabilities as of December 31, 2016 and 2015, but had no effect on our financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

NOTE 2 — 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.

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 Company’s 2017 Convertible Notes and the Company’s 7 1⁄2% Senior Notes due 2022 (the "2022 Notes") (collectively, the "Notes" and the holders thereof, the "Noteholders") 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 (a) 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") among Stone as borrower, Bank of America, N.A. as administrative agent and issuing bank, and the financial institutions named therein, and (b) 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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Upon emergence from bankruptcy by the Debtors, and 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, 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) $100,000 of cash, (b) 95% of the common stock in reorganized Stone and (c) $225,000 of new 7.5% second lien notes due 2022 (the "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 to15% 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 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 $25,000, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA, defined below.


•	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 $1,191,500 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 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 completion of the sale of the Appalachia Properties. Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360,000 in cash, subject to customary purchase price adjustments. In connection with the execution of the Tug Hill PSA, Tug Hill deposited $5,000 in escrow.

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, and 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 $527,000 in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court. See Note 21 – Subsequent Events. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors' may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to rejected contracts or leases may assert unsecured claims against the Debtors, as applicable, for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors, including where applicable a quantification of the

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Company's obligations under any such executory contact or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code.

Potential Claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims are required to file proofs of claim by the deadline for general claims (the "bar date"). Differences between amounts scheduled by the Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and will likely continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

Liabilities Subject to Compromise

We have applied ASC 852 in preparing our consolidated financial statements for periods subsequent to the filing of the Bankruptcy Petitions. The consolidated financial statements include amounts classified as "liabilities subject to compromise", which represent our current estimate of known or potential obligations to be resolved in connection with our Chapter 11 proceedings. Differences between liabilities we have estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts prospectively as necessary. Such adjustments may be material.

The following table summarizes the components of liabilities subject to compromise included in the Company's consolidated balance sheet as of December 31, 2016:



	December 31, 2016
1 3⁄4% Senior Convertible Notes due 2017	$	300,000
7 1⁄2% Senior Notes due 2022	775,000
Accrued interest payable	35,182
Liabilities subject to compromise	$	1,110,182

Reorganization Items

Under ASC 852, the direct and incremental costs resulting from the reorganization and restructuring of the business are reported separately as reorganization items on the statement of operations. The following table summarizes the components of reorganization items in the Company’s consolidated statement of operations for the year ended December 31, 2016:



	Twelve Months Ended December 31, 2016
Professional fees	$	2,615
Write-off of unamortized deferred financing costs	4,792
Write-off of unamortized discount and premium of Notes	3,540
Reorganization items	$	10,947

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NOTE 3 — GOING CONCERN:

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. The significant decline in commodity prices since mid-2014 resulted in reduced revenue and cash flows and negatively impacted our liquidity position in 2015 and 2016. Additionally, the level of our indebtedness as of February 23, 2017 and the depressed commodity price environment presented challenges related to our ability to comply with the covenants in the agreements governing such indebtedness. The minimum liquidity requirement and other restrictions under the Credit Facility also presented challenges with respect to our ability to meet interest payment obligations on the 2022 Notes as well as the maturity of the 2017 Convertible Notes. In order to address these issues, we worked with financial and legal advisors throughout 2016, structuring a plan of reorganization to address our liquidity and capital structure, and on December 14, 2016, the Debtors filed 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. Based upon the facts and circumstances that existed as of February 23, 2017, while we expected the Plan to become effective on February 28, 2017, at which point we would emerge from bankruptcy, there could be no assurance that the effectiveness of the Plan would occur on such date, or at all. The uncertainty surrounding our Chapter 11 proceedings raised substantial doubt about our ability to continue as a going concern as of February 23, 2017.

In accordance with the Plan, we completed the sale of the Appalachia Properties to EQT on February 27, 2017 for net consideration of approximately $522,472. On February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Upon emergence from bankruptcy, we eliminated approximately $1,191,500 in principal amount of outstanding debt, resulting in remaining debt outstanding of approximately $236,284 on the effective date, consisting of $225,000 of Second Lien Notes and $11,284 outstanding under the Building Loan. As a result of the execution of the Plan, management has concluded that there is no longer substantial doubt about the Company's ability to continue as a going concern.

NOTE 4 — EARNINGS PER SHARE:

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods (in thousands, except per share amounts):



	Year Ended December 31,
	2016		2015		2014
Income (numerator):
Basic:
Net loss	$	(590,586)	$	(1,090,915)	$	(189,543)
Net income attributable to participating securities	—		—		—
Net loss attributable to common stock - basic	$	(590,586)	$	(1,090,915)	$	(189,543)
Diluted:
Net loss	$	(590,586)	$	(1,090,915)	$	(189,543)
Net income attributable to participating securities	—		—		—
Net loss attributable to common stock - diluted	$	(590,586)	$	(1,090,915)	$	(189,543)
Weighted average shares (denominator):
Weighted average shares - basic	5,591		5,525		5,272
Dilutive effect of stock options	—		—		—
Weighted average shares - diluted	5,591		5,525		5,272
Basic loss per share	$	(105.63)	$	(197.45)	$	(35.95)
	$	(105.63)	$	(197.45)	$	(35.95)

All outstanding stock options were considered antidilutive during the years ended December 31, 2016 (12,900 shares), December 31, 2015 (14,400 shares) and December 31, 2014 (20,500 shares) because we had net losses for such years.

During the years ended December 31, 2016, 2015 and 2014, approximately 79,621, 41,375 and 38,034 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock, the granting of stock awards and the exercise of stock options by employees and nonemployee directors. In May 2014, 575,000 shares of our common stock were issued in a public offering.

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For the years ended December 31, 2016, 2015 and 2014, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such years. For the years ended December 31, 2016, 2015 and 2014, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 11 – Debt) and therefore, such warrants were not dilutive for such years. Based on the terms of the Purchased Call Options (as defined in Note 11 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.

On February 15, 2017, our Plan was confirmed by the Bankruptcy Court. The Plan provides, as discussed in Note 2 – Chapter 11 Proceedings, that the Company's currently authorized common stock will be cancelled as of the consummation date of the Bankruptcy Proceedings. On such date, existing holders of common stock in 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.

NOTE 5 — ACCOUNTS RECEIVABLE:

In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts:



	As of December 31,
	2016		2015
Other co-venturers	$	3,532	$	4,639
Trade	42,944		26,224
Unbilled accounts receivable	591		1,736
Other	1,397		15,432
Total accounts receivable	$	48,464	$	48,031

NOTE 6 — CONCENTRATIONS:

Sales to Major Customers

Our production is sold on month-to-month contracts at prevailing prices. We obtain credit protections, such as parental guarantees, from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our total oil and natural gas revenue during the indicated periods:



	Year Ended December 31,
	2016		2015		2014
Phillips 66 Company	68	%	53	%	31	%
Shell Trading (US) Company	10	%	13	%	32	%

The maximum amount of credit risk exposure at December 31, 2016 relating to these customers was $27,736.

We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Production and Reserve Volumes – Unaudited

Approximately 66% of our estimated proved reserve volumes at December 31, 2016 and 65% of our production during 2016 were associated with our GOM deep water, conventional shelf and deep gas properties. Approximately 34% of our estimated proved reserve volumes at December 31, 2016 and 35% of our production during 2016 were associated with the Appalachia Properties.

Cash and Cash Equivalents

A substantial portion of our cash balances are not federally insured.

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NOTE 7 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.

During 2016, 2015 and 2014, a portion of our oil and natural gas production was hedged with fixed-price swaps and collars with various counterparties. We did not have any outstanding derivative contracts at December 31, 2016. 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. As of February 23, 2017, our outstanding fixed-price swaps and put contracts are with Natixis, Bank of America Merrill Lynch, The Toronto-Dominion Bank and The Bank of Nova Scotia.

Our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange ("NYMEX") closing price for West Texas Intermediate ("WTI") crude oil during the entire calendar month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Our put contract settlements are based on the average of the NYMEX closing price for WTI crude oil during the entire calendar month.

The following tables illustrate our derivative positions for calendar years 2017 and 2018 as of February 23, 2017:



		Put Contracts (NYMEX)
		Oil
		Cost of Put		Daily Volume	Price
		($ in thousands)		(Bbls/d)	($ per Bbl)
2017	February - December	$	752	1,000	$	50.00
2017	February - December	802		1,000	50.00
2018	January - December	2,183		1,000	54.00



		Fixed-Price Swaps (NYMEX)
		Oil
		Daily Volume	Swap Price
		(Bbls/d)	($ per Bbl)
2017	March - December	1,000	$	53.90
2018	January - December	1,000	52.50

All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we typically enter into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At February 23, 2017, our derivative instruments were with four counterparties, one of which hedged approximately 37% of our total contracted volumes and three of which each hedged approximately 21% of our total contracted volumes. All of our outstanding derivative instruments are with lenders under our current bank credit facility.

We previously discontinued hedge accounting for certain 2015 natural gas contracts, as it became no longer probable, subsequent to the sale of our non-core GOM conventional shelf properties, that our GOM natural gas production would be sufficient to cover the GOM volumes hedged. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract.

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Derivatives qualifying as hedging instruments:

We had no outstanding hedging instruments at December 31, 2016. The following table discloses the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2015.



Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2015
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	38,576	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	38,576		$	—

The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2016, 2015 and 2014:



Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Years Ended December 31, 2016, 2015, and 2014
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives		Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)			Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
			Location			Location
	2016			2016			2016
Commodity contracts	$	(1,648)	Operating revenue - oil/natural gas production	$	35,457	Derivative income (expense), net	$	(810)
Total	$	(1,648)		$	35,457		$	(810)

	2015			2015			2015
Commodity contracts	$	52,630	Operating revenue - oil/natural gas production	$	149,955	Derivative income (expense), net	$	2,713
Total	$	52,630		$	149,955		$	2,713

	2014			2014			2014
Commodity contracts	$	136,097	Operating revenue - oil/natural gas production	$	526	Derivative income (expense), net	$	5,721
Total	$	136,097		$	526		$	5,721

(a)

For the year ended December 31, 2016, effective hedging contracts increased oil revenue by $23,747 and increased natural gas revenue by $11,710. For the year ended December 31, 2015, effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338. For the year ended December 31, 2014, effective hedging contracts increased oil revenue by $7,929 and decreased natural gas revenue by $7,403.

Derivatives not qualifying as hedging instruments:

Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the years ended December 31, 2016, 2015 and 2014.

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Gain (Loss) Recognized in Derivative Income (Expense)
	Year Ended
Description	December 31, 2016		December 31, 2015		December 31, 2014
Commodity contracts:
Cash settlements	$	—	$	17,385	$	1,484
Change in fair value	—		(12,146)		12,146
Total gain on non-qualifying derivatives	$	—	$	5,239	$	13,630

Offsetting of derivative assets and liabilities:

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. We had no outstanding derivative contracts as of December 31, 2016. As of December 31, 2015, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

NOTE 8 — FAIR VALUE MEASUREMENTS:

U.S. GAAP establishes a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of December 31, 2016 and 2015, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 7 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

We had no liabilities measured at fair value on a recurring basis at December 31, 2016 and 2015. The following tables present our assets that are measured at fair value on a recurring basis at December 31, 2016 and 2015:



	Fair Value Measurements at
	December 31, 2016
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,746	$	8,746	$	—	$	—
Total	$	8,746	$	8,746	$	—	$	—

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	Fair Value Measurements at
	December 31, 2015
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,499	$	8,499	$	—	$	—
Derivative contracts	38,576		—		36,603		1,973
Total	$	47,075	$	8,499	$	36,603	$	1,973

The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2016.



	Hedging Contracts, net
Balance as of January 1, 2016	$	1,973
Total gains/(losses) (realized or unrealized):
Included in earnings	1,111
Included in other comprehensive income	(1,910)
Purchases, sales, issuances and settlements	(1,174)
Transfers in and out of Level 3	—
Balance as of December 31, 2016	$	—
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2016	$	—

The fair value of cash and cash equivalents approximated book value at December 31, 2016 and 2015. As of December 31, 2016 and 2015, the fair value of the liability component of the 2017 Convertible Notes was approximately $293,530 and $217,117, respectively. As of December 31, 2016 and 2015, the fair value of the 2022 Notes was approximately $465,000 and $271,250, respectively.

The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 11 – Debt) at inception and at December 31, 2016 and 2015. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

NOTE 9 — ASSET RETIREMENT OBLIGATIONS:

The change in our asset retirement obligations during the years ended December 31, 2016, 2015 and 2014 is set forth below:



	Year Ended December 31,
	2016		2015		2014
Asset retirement obligations as of the beginning of the year, including current portion	$	225,866	$	316,409	$	502,513
Liabilities incurred	2,338		15,933		28,606
Liabilities settled	(19,630)		(72,713)		(55,839)
Divestment of properties	—		(248)		(137,801)
Accretion expense	40,229		25,988		28,411
Revision of estimates	(6,784)		(59,503)		(49,481)
Asset retirement obligations as of the end of the year, including current portion	$	242,019	$	225,866	$	316,409

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NOTE 10 — INCOME TAXES:

An analysis of our deferred taxes follows:



	As of December 31,
	2016		2015
Tax effect of temporary differences:
Net operating loss carryforwards	$	201,557	$	31,624
Oil and gas properties	85,772		76,766
Asset retirement obligations	85,312		79,618
Stock compensation	3,294		5,199
Hedges	—		(13,598)
Accrued incentive compensation	954		1,234
Debt issuance costs	7,480		—
Other	441		(722)
Total deferred tax assets (liabilities)	384,810		180,121
Valuation allowance	(384,810)		(180,121)
Net deferred tax assets (liabilities)	$	—	$	—

We estimate that we had ($5,674), ($44,096) and $159 of current federal income tax expense (benefit) for the years ended December 31, 2016, 2015 and 2014, respectively. For the years ended December 31, 2016, 2015 and 2014, we recorded deferred income tax expense (benefits) of $13,080, ($272,311) and ($102,177), respectively. The deferred income tax benefits were a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 17 – Supplemental Information on Oil and Natural Gas Operations – Unaudited). We had current income tax receivables of $26,086 and $46,174 at December 31, 2016 and 2015, respectively, both of which related to expected tax refunds from the carryback of net operating losses to previous tax years.

For tax reporting purposes, net operating loss carryforwards totaled approximately $599,144 at December 31, 2016. If not utilized, the majority of such carryforwards would expire in 2035 and would fully expire in 2036. In addition, we had approximately $1,050 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of December 31, 2016, our valuation allowance totaled $384,810. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.

A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:



	Year Ended December 31,
	2016	2015	2014
Income tax expense computed at the statutory federal income tax rate	35.0%	35.0%	35.0%
State taxes	0.2	0.6	1.0
Change in valuation allowance	(35.0)	(12.8)	—
IRC Sec. 162(m) limitation	(0.3)	(0.1)	(0.5)
Tax deficits on stock compensation	(0.7)	(0.1)	(0.2)
Reorganization fees	(0.3)	—	—
Other	(0.2)	(0.1)	(0.3)
Effective income tax rate	(1.3)%	22.5%	35.0%

Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($13,080), ($35,737) and $49,601 for the years ended December 31, 2016, 2015 and 2014, respectively.

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As of December 31, 2016, we had unrecognized tax benefits of $491. If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows:



Total unrecognized tax benefits as of December 31, 2015	$	491
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period	—
Tax positions taken during the current period	—
Settlements with taxing authorities	—
Lapse of applicable statute of limitations	—
Total unrecognized tax benefits as of December 31, 2016	$	491

Our unrecognized tax benefits pertain to a proposed state income tax audit adjustment. We believe that our unrecognized tax benefits may be reduced to zero within the next 12 months upon completion and ultimate settlement of the examination.

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized $46 of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2016. We recognized $131 of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015. No such amounts were recognized for the year ended December 31, 2014. The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2013 through 2016 remain subject to examination by major tax jurisdictions.

NOTE 11 — DEBT:

Our debt consisted of the following at:



	December 31,
	2016		2015
1 3⁄4% Senior Convertible Notes due 2017	$	300,000	$	279,244
7 1⁄2% Senior Notes due 2022	775,000		770,009
Revolving credit facility	341,500		—
4.20% Building Loan	11,284		11,702
Total debt	$	1,427,784	$	1,060,955
Less: current portion of long-term debt	(408)		—
Less: liabilities subject to compromise (see Note 2)	(1,075,000)		—
Long-term debt	$	352,376	$	1,060,955

Bankruptcy Filing

On December 14, 2016, the Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. 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. On February 15, 2017, the Bankruptcy Court confirmed the Plan. See Note 2 – Chapter 11 Proceedings for additional information on the Bankruptcy Proceedings.

Current Portion of Long-Term Debt

As of December 31, 2016, the current portion of long-term debt of $408 represented principal payments due within one year on the 4.20% Building Loan (the "Building Loan").

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Reclassification of Debt

The face value of the 2017 Convertible Notes of $300,000 and the 2022 Notes of $775,000 have been reclassified as liabilities subject to compromise in the accompanying consolidated balance sheet at December 31, 2016. Additionally, we recognized a charge of approximately $8,332 to write-off the remaining unamortized deferred financing costs, discounts and premiums related to the 2017 Convertible Notes and 2022 Notes and a charge of $2,615 for costs directly related to the bankruptcy proceedings, including legal and financial advisory costs for Stone, our bank group and our noteholders incurred post-bankruptcy filing, which are included in reorganization items in the accompanying consolidated statement of operations for the year ended December 31, 2016. See Note 1 – Organization and Summary of Significant Accounting Policies.

Revolving Credit Facility

On June 24, 2014, we entered into the Credit Facility with commitments totaling $900,000 (subject to borrowing base limitations) through a syndicated bank group, with an initial borrowing base of $500,000. The Credit Facility matures on July 1, 2019. On April 13, 2016, our borrowing base under the Credit Facility was reduced from $500,000 to $300,000. On that date, we had $457,000 of outstanding borrowings and $18,269 of outstanding letters of credit, or $175,269 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. We elected to pay the deficiency in six equal monthly installments, making the first payment of $29,212 on May 13, 2016 and the second payment of $29,212 on June 13, 2016.

On June 14, 2016, we entered into Amendment No. 3 (the "June Amendment") to the Credit Facility to (i) increase the borrowing base to $360,000 from $300,000, (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 $125,000 until January 15, 2017, (vi) impose limitations on capital expenditures of $60,000 for the period of June 1, 2016 through December 31, 2016, but allowing for an additional $25,000 to be expended for Appalachian drilled but uncompleted wells, (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 $50,000 to apply after December 10, 2016. Upon execution of the June Amendment, we repaid $56,845 in borrowings under the Credit Facility, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the Credit Facility in conformity with the borrowing base limitation.

As of December 31, 2016 and February 23, 2017, we had $341,500 of outstanding borrowings and $12,469 of outstanding letters of credit, leaving $6,031 of availability under the Credit Facility. The weighted average interest rate under the Credit Facility was approximately 3.2% at December 31, 2016. Subject to certain exceptions, the Credit Facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of December 31, 2016, the Credit Facility was guaranteed by our only material subsidiary, Stone Offshore. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore.

The borrowing base under the 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 Credit 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. The 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. Interest on loans under the Credit Facility is calculated using the London Interbank Offering ("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 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 Credit Facility also includes

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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. We were in compliance with all covenants as of December 31, 2016, however, the Bankruptcy Petitions constituted an event of default that accelerated the Company's obligations under the Credit Facility, resulting in the principal and interest due thereunder immediately due and payable. Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions, and the lenders' rights of enforcement in respect of such amounts were subject to the applicable provisions of the Bankruptcy Code.

On December 14, 2016, the Debtors and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA, pursuant to which 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 $25,000, 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 $200,000, subject to a $150,000 borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. Additionally, the Consolidated Funded Leverage financial covenant will be adjusted to levels ranging from 2.50 to 1 to 3.00 to 1 for 2017 and ranging from 2.50 to 1 to 3.50 to 1 thereafter. The margin for loans at the LIBOR rate will be increased to a range of 3.00% to 4.00%.

Building Loan

On November 20, 2015, we entered into an $11,802 term loan agreement, the Building Loan, maturing on December 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of $73 commencing on December 20, 2015. The Building Loan is collaterized 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.

2017 Convertible Notes

On March 6, 2012, we issued in a private offering $300,000 in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of 23.4449 shares of our common stock per $1 principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately $42.65 per share of our common stock at the time of the issuance of the 2017 Convertible Notes. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock (see Note 1 – Organization and Summary of Significant Accounting Policies). Proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of 2.34449 shares of our common stock with a corresponding conversion price of $426.50 per share. On December 31, 2016, our closing share price was $7.15.

The 2017 Convertible Notes may be converted by the holder, in multiples of $1 principal amount, under certain circumstances, including on or after December 1, 2016, and prior to the close of business on the second scheduled trading day immediately preceding the maturity date of the 2017 Convertible Notes, which is March 1, 2017, without regard to the conditions specified in the indenture governing the 2017 Convertible Notes.

Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock. If we satisfy our conversion obligation solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of our common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture related to the 2017 Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture related to the 2017 Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 2017 Convertible Notes will not receive any cash payment representing accrued and unpaid interest. Instead, interest will be deemed to be paid by the cash, shares of our common stock or a combination of cash and shares of our common stock paid or delivered, as the case may be, upon conversion of a 2017 Convertible Note.

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The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s), and interest is payable on the 2017 Convertible Notes each March 1 and September 1. On the maturity date, each holder will be entitled to receive $1 in cash for each $1 in principal amount of 2017 Convertible Notes, together with any accrued and unpaid interest to, but excluding, the maturity date.

In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the "Purchased Call Options") with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the "Dealers"). We paid an aggregate amount of approximately $70,830 to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately 703,347 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes (after the effectiveness of the reverse stock split of 1-for-10), also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.

We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 703,347 shares of our common stock (the "Sold Warrants") at a strike price of $559.10 per share of our common stock (after the effectiveness of the reverse stock split of 1-for-10). We received aggregate proceeds of approximately $40,170 from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.

The filing of the Bankruptcy Petitions resulted in an event of default and the early termination of the convertible note hedge transactions. Any efforts to enforce payment obligations under the indenture governing the 2017 Convertible Notes were automatically stayed as a result of the Chapter 11 filings.

As of December 31, 2016, the principal amount of the 2017 Convertible Notes of $300,000 was classified as liabilities subject to compromise. During the year ended December 31, 2016, we recognized $15,407 of interest expense for the amortization of the discount and $1,471 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2015, we recognized $15,019 of interest expense for the amortization of the discount and $1,434 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2014, we recognized $13,951 of interest expense for the amortization of the discount and $1,332 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2016, we recognized $5,010 of interest expense and during each of the years ended December 31, 2015 and 2014, we recognized $5,250 of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

2022 Notes

On November 8, 2012, we completed the public offering of $300,000 aggregate principal amount of our 2022 Notes, which are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $293,203. On November 27, 2013, we completed the public offering of an additional $475,000 aggregate principal amount of our 2022 Notes at a 3% premium. The net proceeds from this offering after deducting underwriting discounts, commissions, fees and expenses totaled $480,195. The 2022 Notes rank equally in right of payment with all of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt. The 2022 Notes mature on November 15, 2022, and interest is payable on the 2022 Notes on each May 15 and November 15. We may redeem some or all of the 2022 Notes at any time on or after November 15, 2017 at the redemption prices specified in the indenture, and we may redeem some or all of the 2022 Notes prior to November 15, 2017 at a make-whole redemption price as specified in the indenture. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or we experience certain changes of control, each as described in the indenture, we must offer to repurchase the 2022 Notes. The 2022 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2022 Notes a right to accelerate payment.

We had an interest payment obligation under our 2022 Notes of approximately $29,063, due on November 15, 2016. 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, which would give the trustee or the holders of at least 25% in principal amount of the 2022 Notes the option to accelerate payment of the principal plus accrued and unpaid interest on the 2022 Notes. Although we had sufficient liquidity to make the interest payment by the due date, we elected to not make this interest payment on the due date and utilized the 30-day grace period provided by the indenture prior to entering into the Chapter 11 proceedings. The filing of the Bankruptcy Petitions constituted an event of default under the indenture governing

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the 2022 Notes, but any efforts to enforce such payment obligation were automatically stayed as a result of the Chapter 11 filings. The principal amount of $775,000 of the 2022 Notes was classified as liabilities subject to compromise at December 31, 2016.

Deferred Financing Cost and Interest Cost

We recognized a charge to write-off the remaining unamortized deferred financing costs, premiums and discounts related to the 2017 Convertible Notes and the 2022 Notes as of the Petition Date, which is included in reorganization items on the consolidated statement of operations. See Note 1 – Organization and Summary of Significant Accounting Policies. At December 31, 2016, approximately $63 of unamortized deferred financing costs were deducted from the carrying amount of the Building Loan. At December 31, 2015, approximately $6,869 of unamortized deferred financing costs, premiums and discounts were included within the carrying amount of the related debt liabilities for the 2017 Convertible Notes, 2022 Notes and Building Loan. The deferred financing costs, net of accumulated amortization, of $2,761 and $2,845 at December 31, 2016 and 2015, respectively, related to the Credit Facility are classified as other assets.

Prior to the filing of the Bankruptcy Petitions, the costs associated with the 2017 Convertible Notes were being amortized over the life of the notes using a method that applied an effective interest rate of 7.51%. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes were being amortized over the life of the notes using a method that applied effective interest rates of 7.75% and 7.04%, respectively.

The costs associated with the issuance of the Building Loan are being amortized using the effective interest method over the term of the Building Loan. The costs associated with the Credit Facility are being amortized on a straight-line basis over the term of the facility.

Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2016, 2015 and 2014 was $91,092, $85,267 and $84,577, respectively. In accordance with the accounting guidance in ASC 852, we have accrued interest on the Notes only up to the Petition Date, and such amounts are included as liabilities subject to compromise in our consolidated balance sheet at December 31, 2016. Accordingly, there was no interest expense recognized on the 2017 Convertible Notes or the 2022 Notes after the Bankruptcy Petitions were filed.

NOTE 12 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016, 2015 and 2014. During the year ended December 31, 2016, we reclassified approximately $6,081 of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC. See Note 1 - Organization and Summary of Significant Accounting Policies.



	Cash Flow Hedges		Foreign Currency Items		Total
For the Year Ended December 31, 2016
Beginning balance, net of tax	$	24,025	$	(6,073)	$	17,952
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(1,648)		—		(1,648)
Foreign currency translations	—		(8)		(8)
Income tax effect	581		—		581
Net of tax	(1,067)		(8)		(1,075)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	35,457		—		35,457
Other operational expenses	—		(6,081)		(6,081)
Income tax effect	(12,499)		—		(12,499)
Net of tax	22,958		(6,081)		16,877
Other comprehensive income (loss), net of tax	(24,025)		6,073		(17,952)
Ending balance, net of tax	$	—	$	—	$	—

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	Cash Flow Hedges		Foreign Currency Items		Total
For the Year Ended December 31, 2015
Beginning balance, net of tax	$	86,783	$	(3,468)	$	83,315
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	52,630		—		52,630
Foreign currency translations	—		(2,605)		(2,605)
Income tax effect	(19,096)		—		(19,096)
Net of tax	33,534		(2,605)		30,929
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	149,955		—		149,955
Derivative income, net	1,170		—		1,170
Income tax effect	(54,833)		—		(54,833)
Net of tax	96,292		—		96,292
Other comprehensive loss, net of tax	(62,758)		(2,605)		(65,363)
Ending balance, net of tax	$	24,025	$	(6,073)	$	17,952



	Cash Flow Hedges		Foreign Currency Items		Total
For the Year Ended December 31, 2014
Beginning balance, net of tax	$	(1,395)	$	(667)	$	(2,062)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	136,097		—		136,097
Foreign currency translations	—		(2,801)		(2,801)
Income tax effect	(48,995)		—		(48,995)
Net of tax	87,102		(2,801)		84,301
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	526		—		526
Derivative expense, net	(2,208)		—		(2,208)
Income tax effect	606		—		606
Net of tax	(1,076)		—		(1,076)
Other comprehensive income (loss), net of tax	88,178		(2,801)		85,377
Ending balance, net of tax	$	86,783	$	(3,468)	$	83,315

NOTE 13 — SHARE-BASED COMPENSATION:

Prior to December 17, 2015, we maintained the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the "2009 Plan"). The 2009 Plan was originally approved at the 2009 Annual Meeting of Stockholders and was an amendment and restatement of the Company’s 2004 Amended and Restated Stock Incentive Plan (the "2004 Plan"), and it superseded and replaced in its entirety the 2004 Plan. The 2009 Plan provides for the granting of (a) "incentive" stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options ("non-statutory" stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as "awards"). On December 17, 2015, Stone amended and restated the 2009 Plan to incorporate all prior amendments to the 2009 Plan and certain other non-material changes to the 2009 Plan. See Note 16 – Employee Benefit Plans – Stock Incentive Plans for more information.

No stock options have been granted pursuant to the 2009 Plan since its initial effective date on May 28, 2009; however, we have previously granted options under the 2004 Plan that remain outstanding. Stock options previously granted to employees

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vested ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to nonemployee directors vested ratably over a three-year service-vesting period and expire 10 years subsequent to award. We have granted restricted stock awards under the 2009 Plan, which awards typically vest over a one-year or three-year period.

We record share-based compensation expense for share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our financial statements on a straight-line basis over the vesting period of the award.

For the year ended December 31, 2016, we incurred $11,562 of share-based compensation related to restricted stock issuances or granting of stock awards, and of which a total of approximately $3,117 was capitalized into oil and gas properties. For the year ended December 31, 2015, we incurred $17,917 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,593 was capitalized into oil and gas properties. For the year ended December 31, 2014, we incurred $17,051 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,797 was capitalized into oil and gas properties. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.

The Plan, as described in Note 2 – Chapter 11 Proceedings, provides that the Company's common stock will be cancelled and new common stock will be issued upon emergence from bankruptcy. On February 15, 2017, the Plan was confirmed by the Bankruptcy Court and we expect to emerge from bankruptcy on February 28, 2017. Immediately prior to emergence, the vesting of all outstanding, unvested share-based awards for non-executive employees will be accelerated. Upon emergence from bankruptcy, all outstanding, unvested restricted shares held by the Company’s executives will be cancelled and exchanged for a proportionate share of 5% of the common stock of reorganized Stone, plus warrants for ownership of up to 15% of reorganized Stone’s common equity. Vesting will continue in accordance with the applicable vesting provisions of the original awards. All other executive share-based awards will be cancelled upon emergence from bankruptcy.

Stock Options. There were no stock option grants during the years ended December 31, 2016, 2015 or 2014. The following tables include stock option activity during the years ended December 31, 2016, 2015 and 2014 (amounts in tables represent actual values except where indicated otherwise).



	Year Ended December 31, 2016
	Number of Options	Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	14,447	$	269.25
Granted	—	—
Exercised	—	—
Forfeited	—	—
Expired	(1,500)	477.45
Options outstanding, end of period (1)	12,947	245.13		1.4 years	$	—
Options exercisable, end of period	12,947	245.13		1.4 years	—
Options unvested, end of period	—	—		—	—

(1) Exercise prices for stock options outstanding at December 31, 2016 range from $69.70 to $446.70.

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	Year Ended December 31, 2015
	Number of Options	Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	20,497	$	339.36
Granted	—	—
Exercised	—	—
Forfeited	—	—
Expired	(6,050)	506.76
Options outstanding, end of period	14,447	269.25		2.1 years	$	—
Options exercisable, end of period	14,447	269.25		2.1 years	—
Options unvested, end of period	—	—		—	—



	Year Ended December 31, 2014
	Number of Options	Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	33,117	$	393.74
Granted	—	—
Exercised	(25)	462.00
Forfeited	—	—
Expired	(12,595)	482.11
Options outstanding, end of period	20,497	339.36		2.4 years	$	531
Options exercisable, end of period	20,497	339.36		2.4 years	531
Options unvested, end of period	—	—		—	—

Restricted Stock and Other Stock Awards. The fair value of restricted shares and stock awards is typically determined based on the average of our high and low stock prices on the grant date. During the year ended December 31, 2016, we issued 31,313 shares of restricted stock or stock awards valued at $280. During the year ended December 31, 2015, we issued 141,872 shares of restricted stock valued at $23,722. During the year ended December 31, 2014, we issued 67,305 shares of restricted stock valued at $24,593.

A summary of the restricted stock and stock award activity under the 2009 Plan for the years ended December 31, 2016, 2015 and 2014 is as follows (amounts in table represent actual values):



	2016			2015			2014
	Number of Restricted Shares	Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares	Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares	Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period	180,239	$	208.17	129,848	$	299.45	125,334	$	239.07
Issuances	31,313	8.93		141,872	167.21		67,305	365.40
Lapse of restrictions or granting of stock awards	(117,406)	158.79		(63,745)	296.00		(59,731)	245.73
Forfeitures	(13,056)	200.06		(27,736)	223.80		(3,060)	301.54
Restricted stock outstanding, end of period	81,090	$	205.34	180,239	$	208.17	129,848	$	299.45

As of December 31, 2016, there was $2,823 of unrecognized compensation cost related to unvested share-based awards for non-executive employees and $3,318 of unrecognized compensation cost related to unvested restricted shares held by the Company's executives. The current weighted average remaining vesting period of such awards is approximately one year.

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Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital and/or an increase in income tax expense, depending on the pool of available excess tax benefits to offset such deficit. There were no adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting in 2016 or 2015 and such adjustments were ($54) in 2014. Additionally, during 2016, 2015, and 2014, $4,117, $1,314 and $609 of tax deficits were charged to income tax expense, respectively.

NOTE 14 — SHARE REPURCHASE PROGRAM:

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100,000. 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 $7,071, 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 and 2014.

NOTE 15 — COMMITMENTS AND CONTINGENCIES:

Chapter 11 Proceedings

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. See Note 2 – Chapter 11 Proceedings.

Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

Leases

We lease office facilities in Lafayette and New Orleans, Louisiana, Houston, Texas and New Martinsville and Morgantown, West Virginia under the terms of long-term, non-cancelable leases expiring on various dates through 2021. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net annual commitments under all leases, subleases and contracts with non-cancelable terms in excess of 12 months at December 31, 2016 were as follows:



2017	$	877
2018	612
2019	453
2020	453
2021	113

Payments related to our lease obligations for the years ended December 31, 2016, 2015 and 2014 were approximately $676, $2,076 and $966, respectively.

Other Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management ("BOEM") stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565,000. 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 $117,686 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. The bonds represent guarantees

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by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.

In July 2016, BOEM issued a Notice to Lessees ("NTL"), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances 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 $7,000 to $10,000 of incremental financial assurance or bonding for sole liability properties and potentially an additional $30,000 to $60,000 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 that this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.

In connection with our exploration and development efforts, we are contractually committed to the use of drilling rigs and the acquisition of seismic data in the aggregate amount of $28,030 to be incurred over the next two years.

The Oil Pollution Act (the "OPA") imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by the BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in Outer Continental Shelf ("OCS") waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s final rule. In addition, the BOEM has finalized rules that raise OPA's damages liability cap from $75,000 to $133,650.

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NOTE 16 — EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with certain of our current and former officers. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2016, the liability for such vested benefits was approximately $961 and is recorded in current and other long-term liabilities. The deferred compensation plan is described further below.

The following is a brief description of each incentive compensation plan applicable to our employees:

Annual Cash Incentive Compensation Plans

The Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, provided for annual cash incentive bonuses tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. For 2016, we replaced our historical long-term cash and equity-based incentive compensation programs with the 2016 Performance Incentive Compensation Plan (the "2016 Incentive Plan"), pursuant to which incentive cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Stone incurred expenses of $13,475, $2,242, and $10,361, net of amounts capitalized, for each of the years ended December 31, 2016, 2015 and 2014, respectively, related to incentive compensation cash bonuses. See "Key Executive Incentive Plan" below for additional information.

Stock Incentive Plans

During 2016, we maintained the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (as Amended and Restated December 17, 2015), as amended from time to time (the "Amended 2009 Plan"). That plan was originally approved at the 2009 Annual Meeting of Stockholders (the "2009 Plan") and was an amendment and restatement of the Company’s 2004 Amended and Restated Stock Incentive Plan (the "2004 Plan"), and it superseded and replaced in its entirety the 2004 Plan. The Amended 2009 Plan provides for the granting of (a) "incentive" stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options ("non-statutory" stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as "awards"). The 2009 Plan eliminated the automatic grant of stock options or restricted stock awards to nonemployee directors that was provided for in the 2004 Plan so that awards under the 2009 Plan and the Amended 2009 Plan are entirely at the discretion of our board of directors or a designated committee. All options must have an exercise price of not less than the fair market value of our common stock on the date of grant and may not be re-priced without stockholder approval.

At the 2015 Annual Meeting of Stockholders, the stockholders approved the Second Amendment (the "Second Amendment") to the 2009 Plan and the Third Amendment (the "Third Amendment") to the 2009 Plan. The Second Amendment provided, among other things, for an increase in the number of shares of our common stock reserved for issuance under the 2009 Plan by 160,000 shares, effective May 21, 2015, and for an extension of the term of the 2009 Plan to May 21, 2025. The Third Amendment set forth the material terms of the 2009 Plan (i.e., the eligible employees, business criteria and maximum annual per person compensation limits) for purposes of complying with certain requirements of Section 162(m) of the Internal Revenue Code. The Third Amendment did not change the employees eligible to receive compensation under the 2009 Plan, but did (i) allow Stone to grant cash awards (which may or may not be designated as performance awards) under the 2009 Plan, (ii) impose a fixed share number limit on stock-based awards and a fixed dollar limit on cash awards granted during any calendar year under the 2009 Plan to certain individuals, and (iii) add additional business criteria that could be utilized in setting performance goals under the 2009 Plan. The Third Amendment also became effective as of May 21, 2015. On December 17, 2015, Stone amended and restated the 2009 Plan in the form of the Amended 2009 Plan to incorporate all prior amendments to the 2009 Plan (including the Second Amendment and the Third Amendment) and certain other non-material changes to the 2009 Plan.

At the 2016 Annual Meeting of Stockholders, the stockholders approved the adoption of the First Amendment (the "First Amendment") to the Amended 2009 Plan. The First Amendment increased the number of shares of our common stock reserved for issuance under the Amended 2009 Plan by 45,000 shares (as adjusted to reflect our June 2016 reverse stock split), effective May 19, 2016. The stockholders also approved the material terms of the Amended 2009 Plan, as amended by the First Amendment (i.e., the eligible employees, business criteria and maximum annual per person compensation limits) for purposes of complying with certain requirements of Section 162(m) of the Internal Revenue Code.

At December 31, 2016, we had approximately 237,062 additional shares available for issuance pursuant to the Stock Incentive Plan. We have adopted the Stone Energy Corporation 2017 Long-Term Incentive Plan, which is an omnibus equity compensation plan that will replace the Amended 2009 Plan and will become effective upon our emergence from bankruptcy.

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401(k) and Deferred Compensation Plans

The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2016, 2015 and 2014, Stone contributed $1,248, $1,553 and $1,989, respectively, to the plan.

The Stone Energy Corporation Deferred Compensation Plan provides eligible executives and employees with the option to defer up to 100% of their eligible compensation for a calendar year and we could, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our board of directors. In addition, the Board may elect to make discretionary profit sharing contributions to the plan. To date there have been no matching or discretionary profit sharing contributions made by Stone, and in connection with our entry into the Settlement Agreement (defined below), we adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under that plan. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2016 and 2015, plan assets of $8,746 and $8,499, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Change of Control and Severance Plans

On April 7, 2009, we amended and restated our Executive Change of Control and Severance Plan effective as of December 31, 2008 (as so amended and restated, the "Executive Plan"). The Executive Plan also replaced and superseded our Executive Change in Control and Severance Policy that was maintained for certain designated executives (specifically, the CEO and CFO). The Executive Plan provided the Company’s officers terminated in the event of a change of control and upon certain other terminations of employment with change of control and severance benefits as defined in the Executive Plan. Although our CEO did not participate in the Executive Plan, the severance benefits provided to him under his employment agreement were substantially similar to the benefits provided under the Executive Plan. Executives terminated within the scope of the Executive Plan (or their applicable employment agreement) were entitled to certain payments and benefits including the following: (i) any unpaid base salary up to the date of termination; (ii) in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of the executive’s annual base salary and any target bonus at the one hundred percent level; (iii) a lump sum amount representing a pro rata share of the bonus opportunity up to the date of termination at the then projected rate of payout; (iv) in the case of officers other than the CEO and CFO and an involuntary termination occurring outside a change of control period, a lump sum severance payment in an amount equal to the executive’s annual base salary; (v) in the case of officers other than the CEO and CFO and an involuntary termination occurring during a change of control period, a lump sum severance payment in an amount equal to 2.99 times the executive’s annual base salary; and (vi) continued health plan coverage for six months and outplacement services. In the case of the CEO and CFO, if the payments would be "excess parachute payments," the CEO and CFO could receive a potential gross-up payment to reimburse them for excise taxes that might be incurred under Section 4999 of the Internal Revenue Code of 1986, as amended (the "Code"), as well as any additional income taxes resulting from such reimbursement, provided that if it was determined that the executive would be entitled to a gross-up payment but the total to be paid would not exceed 110% of the greatest amount (the "Reduced Amount") that could be paid such that receipt of the total would not give rise to any excise tax, then no gross-up would be paid and the total payments to the executive would be reduced to the Reduced Amount. Also, if a payment would be to a "specified employee" for purposes of Section 409A of the Code, payment would be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a change of control, without regard to whether there is a termination of employment, included the following: (i) lapse of restrictions on restricted stock, (ii) accelerated vesting and cash-out of all in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a pro-rated portion of the projected bonus, if any, for the year of change of control.

On December 13, 2016, the Company entered into an Executive Claims Settlement Agreement (the "Settlement Agreement") with nine members of the Company’s senior executive team (collectively, the "Senior Executives"), subject to approval by the Bankruptcy Court, which occurred on January 10, 2017. The Settlement Agreement provides for the termination of the Executive Plan and the employment agreement entered into with Kenneth H. Beer and the modification of the employment agreements with David H. Welch and Richard L. Toothman, Jr. In connection with the Settlement Agreement, we adopted the Stone Energy Corporation Executive Severance Plan (the "Executive Severance Plan") in which all Senior Executives are allowed to participate. Pursuant to the terms of the Executive Severance Plan, severance payable to each of the Senior Executives remains substantially similar to the prior arrangements, with the exception that (a) the severance amounts payable to each of David H. Welch and Kenneth H. Beer have been reduced from 2.99x annual base salary and target bonus to (i) for Mr. Welch, 1.5x annual base salary and 1.0x the bonus permitted under the Key Executive Incentive Plan ("KEIP"), and (ii) for Mr. Beer, 1.25x annual base salary and 1.0x the bonus permitted under the KEIP; (b) six months of health benefit continuation; (c) all holders of equity awards subject to vesting will automatically vest in the next tranche of time-based equity that would be scheduled to vest; (d) certain outplacement

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services; and (e) all Section 280G gross-up payments to which Senior Executives may have previously been entitled were eliminated in favor of a reduction of payments and/or benefits to each Senior Executive in whole or in part only, if by such reduction, the applicable Senior Executive’s net after-tax benefit will exceed such Senior Executive’s net after-tax benefit if such reductions were not made. Further, the Settlement Agreement amends the employment agreement entered into by the Company with David H. Welch (the "Welch Employment Agreement"), pursuant to which Mr. Welch waives any rights to severance under the Welch Employment Agreement in exchange for participation in the Executive Severance Plan. Mr. Toothman also participates in the Executive Severance Plan but remains eligible to receive special severance benefits if he incurs a qualifying termination of employment in connection with the disposition of the Appalachia Properties.

On December 7, 2007, our board of directors approved and adopted the Stone Energy Corporation Employee Change of Control Severance Plan ("Employee Severance Plan"), as amended and restated to comply with the final regulations under Section 409A of the Code and to provide that said plan will remain in force and effect unless and until terminated by our board of directors. The Employee Severance Plan amended and restated the Company’s previous Employee Change of Control Severance Plan dated November 16, 2006. The Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the six-month period following a change of control, including a resignation by the employee relating to a change in duties. Employees who are terminated within the scope of the Employee Severance Plan will be entitled to certain payments and benefits including the following: (i) a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full $10,000 of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay; (ii) continued health plan coverage for 6 months; (iii) a pro-rated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: (i) lapse of restrictions on restricted stock, (ii) cash-out of in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a lump sum cash payment equal to the product of (1) the number of "restricted shares" of company stock that the employee would have received under the company’s stock plan but did not receive for the time-vested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (2) the price per share of the company’s common stock utilized in effecting the change of control, provided that such amount shall be pro-rated by multiplying such amount by the number of full months that have elapsed from January 1 of that calendar year to the effective date of the change of control and then dividing the result by 12.

Key Executive Incentive Plan

Pursuant to the terms of the Settlement Agreement, the Senior Executives agreed to waive their claims related to the Company’s existing 2016 Incentive Plan, and in exchange therefor, we adopted the Stone Energy Corporation Key Executive Incentive Plan ("KEIP"), in which the Senior Executives are allowed to participate. The Senior Executives no longer have a fourth quarter bonus opportunity under the 2016 Incentive Plan and future payments to Senior Executives under the KEIP shall not be paid until the consummation of the Bankruptcy Cases and are limited to approximately $2,000, or the equivalent of the target bonus under the 2016 Incentive Plan for the fourth quarter of 2016. Future payments to Senior Executives under the KEIP shall be paid 50% upon consummation of the bankruptcy cases and 50% 90 days after the Company exits bankruptcy; provided, however, the Senior Executives must be employed upon consummation of the bankruptcy cases and the 90th day following the Company’s exit from bankruptcy or be terminated without cause in order to receive the respective bonus.

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NOTE 17 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:

At December 31, 2016, 2015 and 2014, our oil and gas properties were located in the United States and Canada.

Costs Incurred

The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore in the continental United States:



	Year Ended December 31,
	2016		2015		2014
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year	$	9,773,457	$	9,348,054	$	8,517,873
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties	3,923		(14,158		44,634
Exploratory costs	17,891		104,169		270,850
Development costs (1)	102,665		266,982		438,334
Salaries, general and administrative costs	21,753		27,984		33,975
Interest	26,634		41,339		45,722
Less: overhead reimbursements	(521)		(913)		(3,334)
Total costs incurred during the year, net of divestitures	172,345		425,403		830,181
Balance, end of year	$	9,945,802	$	9,773,457	$	9,348,054
Accumulated DD&A:
Balance, beginning of year	$	(8,561,472)	$	(6,970,631)	$	(5,908,760)
Provision for DD&A	(215,737)		(277,088)		(335,987)
Write-down of oil and gas properties	(357,079)		(1,314,817)		(351,192)
Sale of proved properties	—		1,064		(374,692)
Balance, end of year	$	(9,134,288)	$	(8,561,472)	$	(6,970,631)
Net capitalized costs – United States, proved and unevaluated	$	811,514	$	1,211,985	$	2,377,423
DD&A per Mcfe	$	2.68	$	3.19	$	3.59

(1) Includes capitalized asset retirement costs of ($4,461), ($43,901) and ($20,305), respectively.



Costs incurred during the year (expensed):
Lease operating expenses	$	79,650	$	100,139	$	176,495
Transportation, processing and gathering expenses	27,760		58,847		64,951
Production taxes	3,148		6,877		12,151
Accretion expense	40,229		25,988		28,411
Expensed costs – United States	$	150,787	$	191,851	$	282,008

Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows.

At March 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128,852 based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included $352 related to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118,649 based on twelve-month average prices, net of applicable differentials, of $43.49 per Bbl of oil, $1.93 per Mcf of natural gas and $9.33 per Bbl of NGLs. At September 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36,484 based on twelve-month average prices, net of

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applicable differentials, of $40.51 per Bbl of oil, $1.99 per Mcf of natural gas and $13.88 per Bbl of NGLs. At December 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $73,094 based on twelve-month average prices, net of applicable differentials, of $40.15 per Bbl of oil, $1.71 per Mcf of natural gas and $9.46 per Bbl of NGLs. The March 31, June 30 and September 30, 2016 write-downs were decreased by $22,986, $18,112 and $9,636, respectively, as a result of hedges. There was no hedging impact on the December 31, 2016 write-down.

At March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491,412 based on twelve-month average prices, net of applicable differentials, of $78.99 per Bbl of oil, $2.96 per Mcf of natural gas and $28.82 per Bbl of NGLs. At June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179,125 based on twelve-month average prices, net of applicable differentials, of $68.68 per Bbl of oil, $2.47 per Mcf of natural gas and $29.13 per Bbl of NGLs. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $295,679 based on twelve-month average prices, net of applicable differentials, of $57.76 per Bbl of oil, $2.44 per Mcf of natural gas and $23.04 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $348,601 based on twelve-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. The March 31, June 30, September 30 and December 31, 2015 write-downs were decreased by $28,687, $47,784, $42,652 and $24,797, respectively, as a result of hedges.

At September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47,130 based on twelve-month average prices, net of applicable differentials, of $94.94 per Bbl of oil, $4.19 per Mcf of natural gas and $41.33 per Bbl of NGLs. At December 31, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $304,062 based on twelve-month average prices, net of applicable differentials, of $89.46 per Bbl of oil, $3.68 per Mcf of natural gas and $36.79 per Bbl of NGLs. The September 30 and December 31, 2014 write-downs were increased by $29,001 and $13,342, respectively, as a result of hedges.

The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the years indicated:



	Year Ended December 31,
Unevaluated oil and gas properties – United States:	2016		2015		2014
Net costs incurred (evaluated) during year:
Acquisition costs	$	(71,378)	$	(115,767)	$	(42,384)
Exploration costs	(21,579)		(16,315)		(186,308)
Capitalized interest	26,634		41,339		45,722
	$	(66,323)	$	(90,743)	$	(182,970)

During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices, we discontinued our business development effort in Canada during 2015 and recognized a full impairment of our Canadian oil and gas properties. The following table discloses certain financial data relative to our oil and gas activities located in Canada:

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	Year Ended December 31,
	2016		2015		2014
Oil and gas properties – Canada:
Balance, beginning of year	$	42,484	$	36,579	$	10,583
Costs incurred during the year (capitalized):
Acquisition costs	(498)		(2,862)		6,956
Exploratory costs	2,168		8,767		19,040
Total costs incurred during the year	1,670		5,905		25,996
Balance, end of year (fully evaluated at December 31, 2016 and 2015 and unevaluated at December 31, 2014)	$	44,154	$	42,484	$	36,579
Accumulated DD&A:
Balance, beginning of year	$	(42,484)	$	—	$	—
Foreign currency translation adjustment	(1,318)		5,146		—
Write-down of oil and gas properties	(352)		(47,630)		—
Balance, end of year	$	(44,154)	$	(42,484)	$	—
Net capitalized costs – Canada	$	—	$	—	$	36,579

The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2016:



	Balance as of		Net Costs Incurred During the Year Ended December 31,
	December 31, 2016		2016		2015		2014		2013 and prior
Acquisition costs	$	122,589	$	8,278	$	17,308	$	47,490	$	49,513
Exploration costs	153,320		34,183		38,686		42,298		38,153
Capitalized interest	97,811		24,759		33,232		32,287		7,533
Total unevaluated costs	$	373,720	$	67,220	$	89,226	$	122,075	$	95,199

Approximately 73 specifically identified drilling projects are included in unevaluated costs at December 31, 2016 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2016, 2015 and 2014 totaled $26,634, $41,339 and $45,722, respectively.

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2016 have been prepared in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and NGL reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves at December 31, 2016, 2015 and 2014 are prepared in accordance with the SEC’s rule, "Modernization of Oil and Gas Reporting," using a historical twelve-month average pricing assumption.

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	Oil (MBbls)	NGLs (MBbls)	Natural Gas (MMcf)	Oil, Natural Gas and NGLs (MMcfe)
Estimated proved reserves as of December 31, 2013	43,827	23,297	460,766	863,513
Revisions of previous estimates	(624)	(331)	(4,631)	(10,362)
Extensions, discoveries and other additions	9,650	7,521	131,617	234,639
Sale of reserves	(4,888)	(556)	(46,483)	(79,151)
Production	(5,568)	(2,114)	(47,426)	(93,515)
Estimated proved reserves as of December 31, 2014	42,397	27,817	493,843	915,124
Revisions of previous estimates	(6,818)	(20,777)	(362,102)	(527,675)
Extensions, discoveries and other additions	862	11	1,499	6,738
Purchase of producing properties	685	1,808	26,136	41,095
Sale of reserves	(859)	—	(1,061)	(6,213)
Production	(5,991)	(2,401)	(36,457)	(86,809)
Estimated proved reserves as of December 31, 2015	30,276	6,458	121,858	342,260
Revisions of previous estimates	(751)	6,352	24,858	58,465
Extensions, discoveries and other additions	63	2	45	435
Production	(6,308)	(2,183)	(29,441)	(80,387)
Estimated proved reserves as of December 31, 2016	23,280	10,629	117,320	320,773
Estimated proved developed reserves:
as of December 31, 2014	22,957	13,743	249,924	470,118
as of December 31, 2015	21,734	4,784	90,262	249,366
as of December 31, 2016	18,269	9,255	90,741	255,884
Estimated proved undeveloped reserves:
as of December 31, 2014	19,440	14,074	243,919	445,006
as of December 31, 2015	8,542	1,674	31,596	92,894
as of December 31, 2016	5,011	1,374	26,579	64,889

The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.

Year Ended December 31, 2016. Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs (92 Bcfe) primarily in Appalachia, slightly offset by negative well performance (35 Bcfe).

Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (570 Bcfe) primarily in Appalachia, slightly offset by positive well performance (42 Bcfe). Purchase of producing properties related to increases in our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.

Year Ended December 31, 2014. Extensions, discoveries and other additions were primarily the result of our Appalachia (118 Bcfe) and our deep water (116 Bcfe) drilling programs. Sale of reserves primarily related to the sale of certain of our non-core GOM conventional shelf properties (63 Bcfe) and our Katie field in Appalachia (15 Bcfe).

Standardized Measure of Discounted Future Net Cash Flow

The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2016. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2016 average historical twelve-month oil and natural gas prices, net of applicable differentials, were $40.15 per Bbl of oil, $9.46 per Bbl of NGLs and $1.71 per Mcf of natural gas. The 2015 average twelve-month oil and natural gas prices, net of applicable differentials, were $51.16 per Bbl of oil, $16.40

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per Bbl of NGLs and $2.19 per Mcf of natural gas. The 2014 average twelve-month oil and natural gas prices, net of applicable differentials, were $89.46 per Bbl of oil, $36.79 per Bbl of NGLs and $3.68 per Mcf of natural gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Our GOM Basin properties represented approximately 66% of our estimated proved oil and natural gas reserves and virtually all of the standardized measure of discounted future net cash flows at December 31, 2016.



	Standardized Measure Year Ended December 31,
	2016		2015		2014
Future cash inflows	$	1,236,097	$	1,921,329	$	6,635,751
Future production costs	(480,815)		(651,396)		(2,413,004)
Future development costs	(638,988)		(679,355)		(1,511,687)
Future income taxes	—		—		(609,516)
Future net cash flows	116,294		590,578		2,101,544
10% annual discount	109,628		13,259		(682,752)
Standardized measure of discounted future net cash flows	$	225,922	$	603,837	$	1,418,792



	Changes in Standardized Measure Year Ended December 31,
	2016		2015		2014
Standardized measure at beginning of year	$	603,837	$	1,418,792	$	1,685,002
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(223,948)		(340,477)		(486,232)
Changes in price, net of future production costs	(448,861)		(237,747)		(864,118)
Extensions and discoveries, net of future production and development costs	5,243		1,573		549,649
Changes in estimated future development costs, net of development costs incurred during the period	54,406		731,115		203,026
Revisions of quantity estimates	139,759		(1,458,652)		(27,495)
Accretion of discount	60,384		174,456		222,009
Net change in income taxes	—		325,768		209,323
Purchases of reserves in-place	—		3,493		—
Sales of reserves in-place	—		—		(152,787)
Changes in production rates due to timing and other	35,102		(14,484)		80,415
Net decrease in standardized measure	(377,915)		(814,955)		(266,210)
Standardized measure at end of year	$	225,922	$	603,837	$	1,418,792

NOTE 18 — OTHER OPERATIONAL EXPENSES:

Included in other operational expenses for the year ended December 31, 2016 is a $6,081 loss on the liquidation of our former foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 12 – Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the year ended December 31, 2016 are approximately $17,741 of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20,000 charge related to the termination of our deep water drilling rig contract with Ensco and $9,889 in charges related to the terminations of the Appalachian drilling rig contract and contracts with two GOM vendors.

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NOTE 19 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:

The results of operations by quarter are as follows:



	2016
	Quarter Ended
	March 31		June 30		September 30		December 31
Operating revenue	$	80,677	$	89,319	$	94,427	$	113,107
Loss from operations	(172,150)		(174,656)		(72,128)		(90,234)
Net loss	(188,784)		(195,761)		(89,635)		(116,406)
Basic loss per share	$	(33.89)	$	(35.05)	$	(16.01)	$	(20.76)
Diluted loss per share	$	(33.89)	$	(35.05)	$	(16.01)	$	(20.76)

Write-down of oil and gas properties	$	129,204	$	118,649	$	36,484	$	73,094
Restructuring fees	$	953	$	9,436	$	5,784	$	13,424
Other operational expenses (1)	$	12,527	$	27,680	$	9,059	$	6,187
Reorganization items	—		—		—		$	10,947

(1) See Note 18 – Other Operational Expenses for additional details.



	2015
	Quarter Ended
	March 31		June 30		September 30		December 31
Operating revenue	$	153,498	$	149,525	$	132,196	$	110,499
Loss from operations	(497,194)		(228,161)		(297,209)		(342,759)
Net loss	(327,388)		(152,906)		(291,965)		(318,656)
Basic loss per share	$	(59.33)	$	(27.68)	$	(52.82)	$	(57.63)
Diluted loss per share	$	(59.33)	$	(27.68)	$	(52.82)	$	(57.63)

Write-down of oil and gas properties	$	491,412	$	224,294	$	295,679	$	351,062

NOTE 20 — NEW YORK STOCK EXCHANGE COMPLIANCE:

On April 29, 2016, we were notified by the New York Stock Exchange ("NYSE") that we were not in compliance with the NYSE's continued listing requirements, as 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, which is the minimum average share price for continued listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than $50,000 over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50,000, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual.

At the close of business on June 10, 2016, we effected a 1-for-10 reverse stock split (see Note 1 – Organization and Summary of Significant Accounting Policies) in order to increase the market price per share 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 $50,000 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. 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 $50,000, 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, including an abnormally low market capitalization. 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

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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 quarter of 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. We expect to submit our fourth quarter 2016 plan update to the NYSE by mid-March 2017.

NOTE 21 — SUBSEQUENT EVENTS:

Confirmation of Plan of Reorganization

On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. See Note 2 – Chapter 11 Proceedings.

Disposition of Appalachia Properties

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. See Note 2 – Chapter 11 Proceedings. 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 $527,000 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 $16,000 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. 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 $10,800. 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. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of our total estimated proved oil and natural gas reserves on a volume equivalent basis.

NOTE 22 — GUARANTOR FINANCIAL STATEMENTS:

Stone Offshore is an unconditional guarantor (the "Guarantor Subsidiary") of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the "Non-Guarantor Subsidiaries") have not provided guarantees. The following presents consolidating financial information as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

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CCONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2016

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	150,537	$	40,044	$	—	$	—	$	190,581
Accounts receivable	18,745		31,452		—		(1,733)		48,464
Current income tax receivable	26,086		—		—		—		26,086
Other current assets	10,151		—		—		—		10,151
Total current assets	205,519		71,496		—		(1,733)		275,282
Oil and gas properties, full cost method:
Proved	1,964,046		7,608,036		44,154		—		9,616,236
Less: accumulated DD&A	(1,964,046)		(7,170,242)		(44,154)		—		(9,178,442)
Net proved oil and gas properties	—		437,794		—		—		437,794
Unevaluated	251,955		121,765		—		—		373,720
Other property and equipment, net	26,213		—		—		—		26,213
Other assets, net	25,570		904		—		—		26,474
Investment in subsidiary	389,475		76		—		(389,551)		—
Total assets	$	898,732	$	632,035	$	—	$	(391,284)	$	1,139,483
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	13,742	$	7,972	$	—	$	(1,733)	$	19,981
Undistributed oil and gas proceeds	14,170		903		—		—		15,073
Accrued interest	809		—		—		—		809
Asset retirement obligations	—		88,000		—		—		88,000
Current portion of long-term debt	408		—		—		—		408
Other current liabilities	18,602		—		—		—		18,602
Total current liabilities	47,731		96,875		—		(1,733)		142,873
Long-term debt	352,376		—		—		—		352,376
Asset retirement obligations	8,410		145,609		—		—		154,019
Other long-term liabilities	17,315		—		—		—		17,315
Total liabilities not subject to compromise	425,832		242,484		—		(1,733)		666,583
Liabilities subject to compromise	1,110,182		—		—		—		1,110,182
Total liabilities	1,536,014		242,484		—		(1,733)		1,776,765
Commitments and contingencies
Stockholders’ equity:
Common stock	56		—		—		—		56
Treasury stock	(860)		—		—		—		(860)
Additional paid-in capital	1,659,731		1,300,547		108,198		(1,408,745)		1,659,731
Accumulated deficit	(2,296,209)		(910,996)		(108,198)		1,019,194		(2,296,209)
Total stockholders’ equity	(637,282)		389,551		—		(389,551)		(637,282)
Total liabilities and stockholders’ equity	$	898,732	$	632,035	$	—	$	(391,284)	$	1,139,483

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CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2015

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,681	$	2	$	1,076	$	—	$	10,759
Accounts receivable	10,597		39,190		—		(1,756)		48,031
Fair value of derivative contracts	—		38,576		—		—		38,576
Current income tax receivable	46,174		—		—		—		46,174
Other current assets	6,848		—		33		—		6,881
Total current assets	73,300		77,768		1,109		(1,756)		150,421
Oil and gas properties, full cost method:
Proved	1,875,152		7,458,262		42,484		—		9,375,898
Less: accumulated DD&A	(1,874,622)		(6,686,849)		(42,484)		—		(8,603,955)
Net proved oil and gas properties	530		771,413		—		—		771,943
Unevaluated	253,308		186,735		—		—		440,043
Other property and equipment, net	29,289		—		—		—		29,289
Other assets, net	16,612		826		1,035		—		18,473
Investment in subsidiary	745,033		—		1,088		(746,121)		—
Total assets	$	1,118,072	$	1,036,742	$	3,232	$	(747,877)	$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	16,063	$	67,901	$	—	$	(1,757)	$	82,207
Undistributed oil and gas proceeds	5,216		776		—		—		5,992
Accrued interest	9,022		—		—		—		9,022
Asset retirement obligations	—		20,400		891		—		21,291
Other current liabilities	40,161		551		—		—		40,712
Total current liabilities	70,462		89,628		891		(1,757)		159,224
Long-term debt	1,060,955		—		—		—		1,060,955
Asset retirement obligations	1,240		203,335		—		—		204,575
Other long-term liabilities	25,204		—		—		—		25,204
Total liabilities	1,157,861		292,963		891		(1,757)		1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock	55		—		—		—		55
Treasury stock	(860)		—		—		—		(860)
Additional paid-in capital	1,648,687		1,344,577		109,795		(1,454,372)		1,648,687
Accumulated deficit	(1,705,623)		(624,824)		(95,306)		720,130		(1,705,623)
Accumulated other comprehensive income (loss)	17,952		24,026		(12,148)		(11,878)		17,952
Total stockholders’ equity	(39,789)		743,779		2,341		(746,120)		(39,789)
Total liabilities and stockholders’ equity	$	1,118,072	$	1,036,742	$	3,232	$	(747,877)	$	1,410,169

F-43

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2016

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Operating revenue:
Oil production	$	9,268	$	271,978	$	—	$	—	$	281,246
Natural gas production	25,276		39,325		—		—		64,601
Natural gas liquids production	22,142		6,746		—		—		28,888
Other operational income	2,657		—		—		—		2,657
Total operating revenue	59,343		318,049		—		—		377,392
Operating expenses:
Lease operating expenses	12,048		67,589		13		—		79,650
Transportation, processing, and gathering expenses	28,091		(331)		—		—		27,760
Production taxes	2,387		761		—		—		3,148
Depreciation, depletion, amortization	67,059		153,020		—		—		220,079
Write-down of oil and gas properties	26,706		330,373		352		—		357,431
Accretion expense	232		39,997		—		—		40,229
Salaries, general and administrative expenses	59,127		(199)		—		—		58,928
Incentive compensation expense	13,475		—		—		—		13,475
Restructuring fees	29,597		—		—		—		29,597
Other operational expenses	49,247		125		6,081		—		55,453
Derivative expense, net	—		810		—		—		810
Total operating expenses	287,969		592,145		6,446		—		886,560
Loss from operations	(228,626)		(274,096)		(6,446)		—		(509,168)
Other (income) expenses:
Interest expense	64,458		—		—		—		64,458
Interest income	(503)		(47)		—		—		(550)
Other income	(482)		(957)		—		—		(1,439)
Other expense	596		—		—		—		596
Reorganization items	10,947		—		—		—		10,947
Loss from investment in subsidiaries	292,618		—		6,446		(299,064)		—
Total other (income) expenses	367,634		(1,004)		6,446		(299,064)		74,012
Loss before taxes	(596,260)		(273,092)		(12,892)		299,064		(583,180)
Provision (benefit) for income taxes:
Current	(5,674)		—		—		—		(5,674)
Deferred	—		13,080		—		—		13,080
Total income taxes	(5,674)		13,080		—		—		7,406
Net loss	$	(590,586)	$	(286,172)	$	(12,892)	$	299,064	$	(590,586)
Comprehensive loss	$	(608,538)	$	(286,172)	$	(12,892)	$	299,064	$	(608,538)

F-44

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2015

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Operating revenue:
Oil production	$	12,804	$	403,693	$	—	$	—	$	416,497
Natural gas production	41,646		41,863		—		—		83,509
Natural gas liquids production	22,375		9,947		—		—		32,322
Other operational income	4,369		—		—		—		4,369
Derivative income, net	—		7,952		—		—		7,952
Total operating revenue	81,194		463,455		—		—		544,649
Operating expenses:
Lease operating expenses	16,264		83,872		3		—		100,139
Transportation, processing, and gathering expenses	50,247		8,600		—		—		58,847
Production taxes	5,631		1,246		—		—		6,877
Depreciation, depletion, amortization	123,724		157,964		—		—		281,688
Write-down of oil and gas properties	785,463		529,354		47,630		—		1,362,447
Accretion expense	365		25,623		—		—		25,988
Salaries, general and administrative expenses	69,147		201		36		—		69,384
Incentive compensation expense	2,242		—		—		—		2,242
Other operational expenses	2,360		—		—		—		2,360
Total operating expenses	1,055,443		806,860		47,669		—		1,909,972
Loss from operations	(974,249)		(343,405)		(47,669)		—		(1,365,323)
Other (income) expenses:
Interest expense	43,907		21		—		—		43,928
Interest income	(327)		(246)		(7)		—		(580)
Other income	(617)		(1,163)		(3)		—		(1,783)
Other expense	434		—		—		—		434
Loss from investment in subsidiaries	231,783		—		47,659		(279,442)		—
Total other (income) expenses	275,180		(1,388)		47,649		(279,442)		41,999
Loss before taxes	(1,249,429)		(342,017)		(95,318)		279,442		(1,407,322)
Provision (benefit) for income taxes:
Current	(44,096)		—		—		—		(44,096)
Deferred	(114,418)		(157,893)		—		—		(272,311)
Total income taxes	(158,514)		(157,893)		—		—		(316,407)
Net loss	$	(1,090,915)	$	(184,124)	$	(95,318)	$	279,442	$	(1,090,915)
Comprehensive loss	$	(1,156,278)	$	(184,124)	$	(95,318)	$	279,442	$	(1,156,278)

F-45

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Operating revenue:
Oil production	$	29,701	$	486,403	$	—	$	—	$	516,104
Natural gas production	86,812		79,682		—		—		166,494
Natural gas liquids production	61,200		24,442		—		—		85,642
Other operational income	7,551		400		—		—		7,951
Derivative income, net	—		19,351		—		—		19,351
Total operating revenue	185,264		610,278		—		—		795,542
Operating expenses:
Lease operating expenses	18,719		157,776		—		—		176,495
Transportation, processing and gathering expenses	53,028		11,923		—		—		64,951
Production taxes	8,324		3,827		—		—		12,151
Depreciation, depletion, amortization	138,313		201,693		—		—		340,006
Write-down of oil and gas properties	351,192		—		—		—		351,192
Accretion expense	230		28,181		—		—		28,411
Salaries, general and administrative expenses	66,430		4		17		—		66,451
Incentive compensation expense	10,361		—		—		—		10,361
Other operational expenses	669		193		—		—		862
Total operating expenses	647,266		403,597		17		—		1,050,880
Income (loss) from operations	(462,002)		206,681		(17)		—		(255,338)
Other (income) expenses:
Interest expense	38,810		45		—		—		38,855
Interest income	(333)		(192)		(49)		—		(574)
Other income	(836)		(1,496)		—		—		(2,332)
Other expense	274		—		—		—		274
Income from investment in subsidiaries	(133,336)		—		(32)		133,368		—
Total other (income) expenses	(95,421)		(1,643)		(81)		133,368		36,223
Income (loss) before taxes	(366,581)		208,324		64		(133,368)		(291,561)
Provision (benefit) for income taxes:
Current	159		—		—		—		159
Deferred	(177,197)		75,020		—		—		(102,177)
Total income taxes	(177,038)		75,020		—		—		(102,018)
Net income (loss)	$	(189,543)	$	133,304	$	64	$	(133,368)	$	(189,543)
Comprehensive income (loss)	$	(104,166)	$	133,304	$	64	$	(133,368)	$	(104,166)

F-46

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2016

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities:
Net loss	$	(590,586)	$	(286,172)	$	(12,892)	$	299,064	$	(590,586)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	67,059		153,020		—		—		220,079
Write-down of oil and gas properties	26,706		330,373		352		—		357,431
Accretion expense	232		39,997		—		—		40,229
Deferred income tax benefit	—		13,080		—		—		13,080
Settlement of asset retirement obligations	(85)		(19,530)		(899)		—		(20,514)
Non-cash stock compensation expense	8,443		—		—		—		8,443
Non-cash derivative expense	—		1,471		—		—		1,471
Non-cash interest expense	18,404		—		—		—		18,404
Non-cash reorganization items	8,332		—		—		—		8,332
Other non-cash expense	168		—		6,080		—		6,248
Change in current income taxes	20,088		—		—		—		20,088
Non-cash loss from investment in subsidiaries	292,618		—		6,446		(299,064)		—
Change in intercompany receivables/payables	43,330		(42,449)		(881)		—		—
(Increase) decrease in accounts receivable	(7,490)		6,078		—		—		(1,412)
(Increase) decrease in other current assets	(3,526)		—		33		—		(3,493)
Increase (decrease) in accounts payable	4,313		(3,287)		—		—		1,026
Increase (decrease) in other current liabilities	10,321		(424)		—		—		9,897
Other	(9,178)		(957)		—		—		(10,135)
Net cash (used in) provided by operating activities	(110,851)		191,200		(1,761)		—		78,588
Cash flows from investing activities:
Investment in oil and gas properties	(86,442)		(151,158)		(352)		—		(237,952)
Investment in fixed and other assets	(1,266)		—		—		—		(1,266)
Change in restricted funds	—		—		1,046		—		1,046
Investment in subsidiaries	—		—		715		(715)		—
Net cash (used in) provided by investing activities	(87,708)		(151,158)		1,409		(715)		(238,172)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000		—		—		—		477,000
Repayments of bank borrowings	(135,500)		—		—		—		(135,500)
Deferred financing costs	(900)		—		—		—		(900)
Repayments of building loan	(423)		—		—		—		(423)
Equity proceeds from parent	—		—		(715)		715		—
Net payments for share-based compensation	(762)		—		—		—		(762)
Net cash used in financing activities	339,415		—		(715)		715		339,415
Effect of exchange rate changes on cash	—		—		(9)		—		(9)
Net change in cash and cash equivalents	140,856		40,042		(1,076)		—		179,822
Cash and cash equivalents, beginning of period	9,681		2		1,076		—		10,759
Cash and cash equivalents, end of period	$	150,537	$	40,044	$	—	$	—	$	190,581

F-47

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2015

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities:
Net loss	$	(1,090,915)	$	(184,124)	$	(95,318)	$	279,442	$	(1,090,915)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	123,724		157,964		—		—		281,688
Write-down of oil and gas properties	785,463		529,354		47,630		—		1,362,447
Accretion expense	365		25,623		—		—		25,988
Deferred income tax benefit	(114,418)		(157,893)		—		—		(272,311)
Settlement of asset retirement obligations	(15)		(72,367)		—		—		(72,382)
Non-cash stock compensation expense	12,324		—		—		—		12,324
Excess tax benefits	(1,586)		—		—		—		(1,586)
Non-cash derivative expense	—		16,440		—		—		16,440
Non-cash interest expense	17,788		—		—		—		17,788
Change in current income taxes	(37,377)		—		—		—		(37,377)
Non-cash loss from investment in subsidiaries	231,783		—		47,659		(279,442)		—
Change in intercompany receivables/payables	9,744		(19,486)		9,742		—		—
Decrease in accounts receivable	34,609		9,084		31		—		43,724
(Increase) decrease in other current assets	1,799		—		(32)		—		1,767
(Increase) decrease in inventory	(1,394)		2,698		—		—		1,304
Decrease in accounts payable	(7,471)		(7,111)		—		—		(14,582)
Increase (decrease) in other current liabilities	(25,989)		53		—		—		(25,936)
Other	256		(1,163)		—		—		(907)
Net cash (used in) provided by operating activities	(61,310)		299,072		9,712		—		247,474
Cash flows from investing activities:
Investment in oil and gas properties	(188,154)		(323,359)		(10,534)		—		(522,047)
Proceeds from sale of oil and gas properties, net of expenses	—		22,839		—		—		22,839
Investment in fixed and other assets	(1,549)		—		—		—		(1,549)
Change in restricted funds	177,647		—		1,820		—		179,467
Investment in subsidiaries	—		—		(9,714)		9,714		—
Net cash used in investing activities	(12,056)		(300,520)		(18,428)		9,714		(321,290)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000		—		—		—		5,000
Repayments of bank borrowings	(5,000)		—		—		—		(5,000)
Deferred financing costs	(68)		—		—		—		(68)
Proceeds from building loan	11,770		—		—		—		11,770
Excess tax benefits	1,586		—		—		—		1,586
Equity proceeds from parent	—		—		9,714		(9,714)		—
Net payments for share-based compensation	(3,127)		—		—		—		(3,127)
Net cash provided by financing activities	10,161		—		9,714		(9,714)		10,161
Effect of exchange rate changes on cash	—		—		(74)		—		(74)
Net change in cash and cash equivalents	(63,205)		(1,448)		924		—		(63,729)
Cash and cash equivalents, beginning of period	72,886		1,450		152		—		74,488
Cash and cash equivalents, end of period	$	9,681	$	2	$	1,076	$	—	$	10,759

F-48

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

(In thousands)



	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities:
Net income (loss)	$	(189,543)	$	133,304	$	64	$	(133,368)	$	(189,543)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	138,313		201,693		—		—		340,006
Write-down of oil and gas properties	351,192		—		—		—		351,192
Accretion expense	230		28,181		—		—		28,411
Deferred income tax (benefit) provision	(177,197)		75,020		—		—		(102,177)
Settlement of asset retirement obligations	(201)		(56,208)		—		—		(56,409)
Non-cash stock compensation expense	11,325		—		—		—		11,325
Non-cash derivative income	—		(18,028)		—		—		(18,028)
Non-cash interest expense	16,661		—		—		—		16,661
Change in current income taxes	158		—		—		—		158
Non-cash income from investment in subsidiaries	(133,336)		—		(32)		133,368		—
Change in intercompany receivables/payables	114,056		(145,250)		31,194		—		—
(Increase) decrease in accounts receivable	1,131		50,514		(34)		—		51,611
Increase in other current assets	(6,238)		—		(6)		—		(6,244)
(Increase) decrease in inventory	2,415		(2,415)		—		—		—
Decrease in accounts payable	(662)		(2,757)		—		—		(3,419)
Decrease in other current liabilities	(16,946)		(2,206)		—		—		(19,152)
Other	(1,755)		(1,496)		—		—		(3,251)
Net cash provided by operating activities	109,603		260,352		31,186		—		401,141
Cash flows from investing activities:
Investment in oil and gas properties	(338,731)		(558,003)		(30,513)		—		(927,247)
Proceeds from sale of oil and gas properties, net of expenses	28,103		214,811		—		—		242,914
Investment in fixed and other assets	(10,182)		—		—		—		(10,182)
Change in restricted funds	(177,647)		—		(425)		—		(178,072)
Investment in subsidiaries	—		—		(31,696)		31,696		—
Net cash used in investing activities	(498,457)		(343,192)		(62,634)		31,696		(872,587)
Cash flows from financing activities:
Proceeds from issuance of common stock	225,999		—		—		—		225,999
Deferred financing costs	(3,371)		—		—		—		(3,371)
Equity proceeds from parent	—		—		31,696		(31,696)		—
Net payments for share-based compensation	(7,182)		—		—		—		(7,182)
Net cash provided by financing activities	215,446		—		31,696		(31,696)		215,446
Effect of exchange rate changes on cash	—		—		(736)		—		(736)
Net change in cash and cash equivalents	(173,408)		(82,840)		(488)		—		(256,736)
Cash and cash equivalents, beginning of period	246,294		84,290		640		—		331,224
Cash and cash equivalents, end of period	$	72,886	$	1,450	$	152	$	—	$	74,488

F-49

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