STONE ENERGY CORP - FORM 10-Q - November 7, 2016

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________________ 
FORM 10-Q
__________________________________________________________ 
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 1-12074
__________________________________________________________ 
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
__________________________________________________________
Delaware
72-1235413
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
625 E. Kaliste Saloom Road
 
Lafayette, Louisiana
70508
(Address of principal executive offices)
(Zip Code)
(337) 237-0410
(Registrant’s telephone number, including area code) 
__________________________________________________________
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
ý
Accelerated filer
¨
Non-accelerated filer
¨  (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  ý
As of November 7, 2016, there were 5,688,410 shares of the registrant’s common stock, par value $.01 per share, outstanding.
 


TABLE OF CONTENTS
 
 
 
Page
 
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
Item 1.
Item 1A.
Item 2.
Item 6.
 
 


PART I – FINANCIAL INFORMATION
 
Item 1. Financial Statements
 
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
(Note 1)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
182,399

 
$
10,759

Accounts receivable
44,063

 
48,031

Fair value of derivative contracts
6,261

 
38,576

Current income tax receivable
19,863

 
46,174

Other current assets
11,176

 
6,881

Total current assets
263,762

 
150,421

Oil and gas properties, full cost method of accounting:
 
 
 
Proved
9,564,561

 
9,375,898

Less: accumulated depreciation, depletion and amortization
(9,054,069
)
 
(8,603,955
)
Net proved oil and gas properties
510,492

 
771,943

Unevaluated
404,226

 
440,043

Other property and equipment, net
27,227

 
29,289

Other assets, net
29,800

 
18,473

Total assets
$
1,235,507

 
$
1,410,169

Liabilities and Stockholders’ Equity
 
 
 
Current liabilities:
 
 
 
Accounts payable to vendors
$
29,259

 
$
82,207

Undistributed oil and gas proceeds
7,439

 
5,992

Accrued interest
22,917

 
9,022

Asset retirement obligations
60,223

 
21,291

Current portion of long-term debt
292,795

 
—

Other current liabilities
10,903

 
40,712

Total current liabilities
423,536

 
159,224

Long-term debt
1,122,945

 
1,060,955

Asset retirement obligations
182,816

 
204,575

Other long-term liabilities
25,871

 
25,204

Total liabilities
1,755,168

 
1,449,958

Commitments and contingencies

 

Stockholders’ equity:
 
 
 
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,605,525 and 5,530,232 shares, respectively
56

 
55

Treasury stock (1,658 shares, at cost)
(860
)
 
(860
)
Additional paid-in capital
1,657,028

 
1,648,687

Accumulated deficit
(2,179,803
)
 
(1,705,623
)
Accumulated other comprehensive income
3,918

 
17,952

Total stockholders’ equity
(519,661
)
 
(39,789
)
Total liabilities and stockholders’ equity
$
1,235,507

 
$
1,410,169


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


1


STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
Operating revenue:
 
 
 
 
 
 
 
Oil production
$
71,116

 
$
105,013

 
$
204,102

 
$
324,105

Natural gas production
15,601

 
17,367

 
43,327

 
72,611

Natural gas liquids production
6,666

 
5,980

 
15,119

 
29,379

Other operational income
1,044

 
1,392

 
1,737

 
3,184

Derivative income, net
—

 
2,444

 
—

 
4,871

Total operating revenue
94,427

 
132,196

 
264,285

 
434,150

Operating expenses:
 
 
 
 
 
 
 
Lease operating expenses
16,976

 
24,244

 
55,349

 
79,250

Transportation, processing and gathering expenses
10,633

 
18,208

 
18,657

 
55,851

Production taxes
835

 
2,052

 
1,894

 
6,394

Depreciation, depletion and amortization
58,918

 
61,936

 
166,707

 
226,309

Write-down of oil and gas properties
36,484

 
295,679

 
284,337

 
1,011,385

Accretion expense
10,082

 
6,498

 
30,147

 
19,315

Salaries, general and administrative expenses
15,425

 
19,552

 
48,193

 
52,977

Incentive compensation expense
2,160

 
794

 
11,809

 
3,621

Restructuring fees
5,784

 
—

 
16,173

 
—

Other operational expenses
9,059

 
442

 
49,266

 
1,612

Derivative expense, net
199

 
—

 
687

 
—

Total operating expenses
166,555

 
429,405

 
683,219

 
1,456,714

Loss from operations
(72,128
)
 
(297,209
)
 
(418,934
)
 
(1,022,564
)
Other (income) expenses:
 
 
 
 
 
 
 
Interest expense
16,924

 
10,872

 
49,764

 
31,709

Interest income
(58
)
 
(47
)
 
(474
)
 
(235
)
Other income
(272
)
 
(411
)
 
(840
)
 
(1,167
)
Other expense
16

 
148

 
27

 
148

Total other expenses
16,610

 
10,562

 
48,477

 
30,455

Loss before income taxes
(88,738
)
 
(307,771
)
 
(467,411
)
 
(1,053,019
)
Provision (benefit) for income taxes:
 
 
 
 
 
 
 
Current
(991
)
 
—

 
(4,178
)
 
—

Deferred
1,888

 
(15,806
)
 
10,947

 
(280,760
)
Total income taxes
897

 
(15,806
)
 
6,769

 
(280,760
)
Net loss
$
(89,635
)
 
$
(291,965
)
 
$
(474,180
)
 
$
(772,259
)
Basic loss per share
$
(16.01
)
 
$
(52.82
)
 
$
(84.90
)
 
$
(139.83
)
Diluted loss per share
$
(16.01
)
 
$
(52.82
)
 
$
(84.90
)
 
$
(139.83
)
Average shares outstanding
5,600

 
5,528

 
5,585

 
5,523

Average shares outstanding assuming dilution
5,600

 
5,528

 
5,585

 
5,523

 
The accompanying notes are an integral part of this statement.


2


STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
Net loss
$
(89,635
)
 
$
(291,965
)
 
$
(474,180
)
 
$
(772,259
)
Other comprehensive income (loss), net of tax effect:
 
 
 
 
 
 
 
Derivatives
(3,467
)
 
(5,353
)
 
(20,107
)
 
(45,691
)
Foreign currency translation
—

 
(246
)
 
6,073

 
(2,567
)
Comprehensive loss
$
(93,102
)
 
$
(297,564
)
 
$
(488,214
)
 
$
(820,517
)
 
The accompanying notes are an integral part of this statement.

3


STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
 
Nine Months Ended
September 30,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(474,180
)
 
$
(772,259
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
166,707

 
226,309

Write-down of oil and gas properties
284,337

 
1,011,385

Accretion expense
30,147

 
19,315

Deferred income tax provision (benefit)
10,947

 
(280,760
)
Settlement of asset retirement obligations
(15,106
)
 
(59,826
)
Non-cash stock compensation expense
6,407

 
9,163

Non-cash derivative expense
1,261

 
10,854

Non-cash interest expense
14,278

 
13,210

Other non-cash expense
6,081

 
—

Change in current income taxes
21,584

 
7,211

Decrease in accounts receivable
3,968

 
33,895

Increase in other current assets
(4,426
)
 
(1,090
)
Increase (decrease) in accounts payable
3,217

 
(11,592
)
Decrease in other current liabilities
(14,222
)
 
(6,753
)
Other
(8,107
)
 
(82
)
Net cash provided by operating activities
32,893

 
198,980

Cash flows from investing activities:
 
 
 
Investment in oil and gas properties
(200,622
)
 
(385,528
)
Proceeds from sale of oil and gas properties, net of expenses
—

 
11,643

Investment in fixed and other assets
(1,231
)
 
(1,455
)
Change in restricted funds
1,046

 
179,475

Net cash used in investing activities
(200,807
)
 
(195,865
)
Cash flows from financing activities:
 
 
 
Proceeds from bank borrowings
477,000

 
5,000

Repayments of bank borrowings
(135,500
)
 
(5,000
)
Repayments of building loan
(285
)
 
—

Deferred financing costs
(900
)
 
—

Net payments for share-based compensation
(752
)
 
(3,127
)
Net cash provided by (used in) financing activities
339,563

 
(3,127
)
Effect of exchange rate changes on cash
(9
)
 
(2
)
Net change in cash and cash equivalents
171,640

 
(14
)
Cash and cash equivalents, beginning of period
10,759

 
74,488

Cash and cash equivalents, end of period
$
182,399

 
$
74,474

 
The accompanying notes are an integral part of this statement.

4


STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
Note 1 – Interim Financial Statements
 
The condensed consolidated financial statements of Stone Energy Corporation (“Stone” or the "Company") and its subsidiaries as of September 30, 2016 and for the three and nine month periods ended September 30, 2016 and 2015 are unaudited and reflect all adjustments (consisting only of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated balance sheet as of December 31, 2015 has been derived from the audited financial statements as of that date contained in our Annual Report on Form 10-K for the year ended December 31, 2015 (our “2015 Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our 2015 Annual Report on Form 10-K. The results of operations for the three and nine month periods ended September 30, 2016 are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period 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 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.
 
Note 2 – Going Concern
 
The accompanying condensed 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 condensed consolidated financial statements. As such, the accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

The level of our indebtedness of $1,428 million as of September 30, 2016 and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness, particularly the maximum Consolidated Funded Debt to consolidated EBITDA (“Consolidated Funded Leverage”) financial covenant set forth in our bank credit agreement. If we exceed the maximum Consolidated Funded Leverage financial covenant, we would be required to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.

On June 14, 2016, we entered into an amendment to the bank credit facility (see Note 5 – Debt) which, among other things, requires that we maintain minimum liquidity of $125.0 million through January 15, 2017 and revised the maximum Consolidated Funded Leverage financial covenant from 3.75 to 1 to 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 ending December 31, 2016 and 3.75 to 1 thereafter. We were in compliance with all covenants under the bank credit facility as of September 30, 2016, however, the minimum liquidity requirement and other restrictions under the credit facility may prevent us from being able to meet our interest payment obligation on the 7½% Senior Notes due in 2022 (the “2022 Notes”) in the fourth quarter of 2016 as well as the subsequent maturity of our 1¾% Senior Convertible Notes due in March 2017 (the “2017 Convertible Notes”). Additionally, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017 unless a material portion of our debt is repaid, reduced or exchanged into equity.


5


As a result of the impact to our financial position from the drastic decline in commodity prices and in consideration of the current level of our indebtedness, we engaged advisors to assist with the evaluation of various strategic alternatives to address our liquidity and capital structure (see Note 12 – Restructuring Fees). On October 20, 2016, we entered into a restructuring support agreement (the “RSA”) with certain holders of our 2017 Convertible Notes and our 2022 Notes (the "Noteholders") to support a restructuring on the terms of a pre-packaged plan of reorganization (the “Plan”). The RSA contemplates that we will file for voluntary relief under chapter 11 of the United States Bankruptcy Code (the "Bankruptcy Code") in a United States Bankruptcy Court (the "Bankruptcy Court") on or before December 9, 2016 to implement the Plan. Pursuant to the terms of the RSA, the Noteholders will receive (a) 95% of the common stock in reorganized Stone, (b) $225 million of new 7.5% second lien notes due 2022 and (c) $150 million of the net cash proceeds from the sale of Stone’s approximately 86,000 net acres in the Appalachia regions of Pennsylvania and West Virginia (the “Properties”) plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any. Additionally, on October 20, 2016, we entered into a purchase and sale agreement (the “PSA”) with TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”). Pursuant to the terms of the PSA, we agreed to sell the Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by Stone of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. On November 4, 2016, we entered into an amendment to the RSA (the “RSA Amendment”) with the Noteholders pursuant to which (a) Stone will be obligated to, at any time upon the written request of the Noteholders or their counsel, provide in writing to counsel to the Noteholders the good faith estimate of Stone – together with documentation requested by the Noteholders or their counsel – of any cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases on both a “per contract” basis and in the aggregate, (b) the Noteholders will have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all such payments exceeds an amount acceptable to the Noteholders, (c) the Noteholders will have the unilateral right to extend the automatic termination of the RSA if the restructuring transactions contemplated by the RSA are not consummated by the one-hundredth (100th) calendar day after the Company files for chapter 11 bankruptcy, and (d) solicitation will commence by November 10, 2016. For additional details on the RSA, RSA Amendment and PSA, see Note 16 – Subsequent Events.

We cannot provide any assurances that we will be able to complete a restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness. We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached. While we expect to continue discussions and related negotiations with our bank credit facility lenders, there can be no assurance that an agreement will be reached. The conditions noted above and the uncertainties surrounding the restructuring, asset sales, renegotiation of our bank credit facility and chapter 11 bankruptcy proceedings raise substantial doubt about our ability to continue as a going concern.

Note 3 – 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:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands, except per share data)
Income (numerator):
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
Net loss
$
(89,635
)
 
$
(291,965
)
 
$
(474,180
)
 
$
(772,259
)
Net income attributable to participating securities
—

 
—

 
—

 
—

Net loss attributable to common stock - basic
$
(89,635
)
 
$
(291,965
)
 
$
(474,180
)
 
$
(772,259
)
Diluted:
 
 
 
 
 
 
 
Net loss
$
(89,635
)
 
$
(291,965
)
 
$
(474,180
)
 
$
(772,259
)
Net income attributable to participating securities
—

 
—

 
—

 
—

Net loss attributable to common stock - diluted
$
(89,635
)
 
$
(291,965
)
 
$
(474,180
)
 
$
(772,259
)
Weighted average shares (denominator):
 
 
 
 
 
 
 
Weighted average shares - basic
5,600

 
5,528

 
5,585

 
5,523

Dilutive effect of stock options
—

 
—

 
—

 
—

Dilutive effect of convertible notes
—

 
—

 
—

 
—

Weighted average shares - diluted
5,600

 
5,528

 
5,585

 
5,523

Basic loss per share
$
(16.01
)
 
$
(52.82
)
 
$
(84.90
)
 
$
(139.83
)
Diluted loss per share
$
(16.01
)
 
$
(52.82
)
 
$
(84.90
)
 
$
(139.83
)
 

6


All outstanding stock options were considered antidilutive during the three and nine months ended September 30, 2016 (approximately 12,900 shares) and during the three and nine months ended September 30, 2015 (approximately 14,400 shares) because we had net losses for such periods.
 
During the three months ended September 30, 2016 and 2015, approximately 12,900 shares and 1,832 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors. During the nine months ended September 30, 2016 and 2015, approximately 75,100 shares and 41,375 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.
 
For the three and nine months ended September 30, 2016 and 2015, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such periods. For the three and nine months ended September 30, 2016 and 2015, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 5 – Debt) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 5 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.
 
Note 4 – 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.
 
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.
 
We have entered into fixed-price swaps and collars with various counterparties for a portion of our expected 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements and oil collar settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract 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. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, The Bank of Nova Scotia and Natixis. Our oil collar contract is with The Bank of Nova Scotia.

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 have entered 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 November 7, 2016, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility. 

7


The following tables illustrate our derivative positions for calendar year 2016 as of November 7, 2016:
 
Fixed-Price Swaps (NYMEX)
 
Natural Gas
 
Oil
 
Daily Volume
(MMBtus/d)
 
Swap Price
($)
 
Daily Volume
(Bbls/d)
 
Swap Price
($)
2016
10,000

 
4.110

 
1,000

 
49.75

2016
10,000

 
4.120

 
1,000

 
52.78

2016


 


 
1,000

 
90.00

 
 
Collar (NYMEX)
 
Oil
 
Daily Volume
(Bbls/d)
 
Floor Price ($)
 
Ceiling Price ($)
2016
1,000

 
45.00

 
54.75


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 Gulf of Mexico ("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. At September 30, 2016, we had accumulated other comprehensive income of $3.9 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of September 30, 2016. The $3.9 million of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.
 
Derivatives qualifying as hedging instruments:
 
The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at September 30, 2016 and December 31, 2015.
Fair Value of Derivatives Qualifying as Hedging Instruments at
September 30, 2016
(In millions)
 
Asset Derivatives
 
Liability Derivatives
Description
Balance Sheet Location
 
Fair
Value
 
Balance Sheet Location
 
Fair
Value
Commodity contracts
Current assets: Fair value of
derivative contracts
 
$
6.3

 
Current liabilities: Fair value
of derivative contracts
 
$
—

 
Long-term assets: Fair value
of derivative contracts
 
—

 
Long-term liabilities: Fair
value of derivative contracts
 
—

 
 
 
$
6.3

 
 
 
$
—

 
 
 
 
 
 
 
 
Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2015
(In millions)
 
Asset Derivatives
 
Liability Derivatives
Description
Balance Sheet Location
 
Fair
Value
 
Balance Sheet Location
 
Fair
Value
Commodity contracts
Current assets: Fair value of
derivative contracts
 
$
38.6

 
Current liabilities: Fair value
of derivative contracts
 
$
—

 
Long-term assets: Fair value
of derivative contracts
 
—

 
Long-term liabilities: Fair
value of derivative contracts
 
—

 
 
 
$
38.6

 
 
 
$
—

 
The following tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and nine month periods ended September 30, 2016 and 2015.

8


Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended September 30, 2016 and 2015
(In millions)
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)
 
 
2016
 
2015
 
Location
 
2016
 
2015
 
Location
 
2016
 
2015
Commodity contracts
 
$
2.3

 
$
31.6

 
Operating revenue -
oil/natural gas production
 
$
7.7

 
$
39.9

 
Derivative income
(expense), net
 
$
(0.2
)
 
$
1.2

Total
 
$
2.3

 
$
31.6

 
 
 
$
7.7

 
$
39.9

 
 
 
$
(0.2
)
 
$
1.2


(a)
For the three months ended September 30, 2016, effective hedging contracts increased oil revenue by $5.3 million and increased natural gas revenue by $2.4 million. For the three months ended September 30, 2015, effective hedging contracts increased oil revenue by $36.3 million and increased natural gas revenue by $3.6 million.
Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Nine Months Ended September 30, 2016 and 2015
(In millions)
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)
 
 
2016
 
2015
 
Location
 
2016
 
2015
 
Location
 
2016
 
2015
Commodity contracts
 
$
(1.7
)
 
$
35.7

 
Operating revenue -
oil/natural gas production
 
$
29.4

 
$
107.1

 
Derivative income
(expense), net
 
$
(0.7
)
 
$
1.7

Total
 
$
(1.7
)
 
$
35.7

 
 
 
$
29.4

 
$
107.1

 
 
 
$
(0.7
)
 
$
1.7


(a)
For the nine months ended September 30, 2016, effective hedging contracts increased oil revenue by $19.7 million and increased natural gas revenue by $9.7 million. For the nine months ended September 30, 2015, effective hedging contracts increased oil revenue by $96.8 million and increased natural gas revenue by $10.3 million.

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 three and nine month periods ended September 30, 2016 and 2015.
Gain (Loss) Recognized in Derivative Income (Expense)
(In millions)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
Description
2016
 
2015
 
2016
 
2015
Commodity contracts:
 
 
 
 
 
 
 
Cash settlements
$
—

 
$
3.8

 
$
—

 
$
11.0

Change in fair value
—

 
(2.6
)
 
—

 
(7.9
)
Total gains (losses) on non-qualifying hedges
$
—

 
$
1.2

 
$
—

 
$
3.1

 
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. As of September 30, 2016 and 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.


9


Note 5 – Debt
 
Our debt balances (net of related unamortized discounts and debt issuance costs) as of September 30, 2016 and December 31, 2015 were as follows:
 
September 30,
2016
 
December 31,
2015
 
(In millions)
1 3⁄4% Senior Convertible Notes due 2017
$
292.4

 
$
279.3

7 1⁄2% Senior Notes due 2022
770.4

 
770.0

Revolving credit facility
341.5

 
—

4.20% Building Loan
11.4

 
11.7

Total debt
1,415.7

 
1,061.0

Less: current portion of long-term debt
(292.8
)
 
—

Long-term debt
$
1,122.9

 
$
1,061.0

 
Current Portion of Long-Term Debt. As of September 30, 2016, the current portion of long-term debt of $292.8 million consisted of $292.4 million of 2017 Convertible Notes and $0.4 million of principal payments due within one year on the Building Loan.

Revolving Credit Facility. On June 24, 2014, we entered into a revolving credit facility (the Fourth Amended and Restated Credit Agreement dated as of June 24, 2014) with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, with an initial borrowing base of $500 million. The bank credit facility matures on July 1, 2019. On April 13, 2016, our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We elected to pay the deficiency in six equal monthly installments, making the first payment of $29.2 million on May 13, 2016 and the second payment of $29.2 million on June 13, 2016.

On June 14, 2016, we entered into Amendment No. 3 (the "Amendment") to the bank credit facility to (i) increase the borrowing base to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ended September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures of $60 million for the period of June 1, 2016 through December 31, 2016, but allowing for an additional $25 million 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 $50.0 million to apply after December 10, 2016. Upon execution of the Amendment, we repaid $56.8 million in borrowings under the credit facility, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation.

On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the Bankruptcy Code on or before December 9, 2016 to implement the Plan (see Note 16 – Subsequent Events). We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached.  While we expect to continue discussions and related negotiations with the lenders under our bank credit facility, there can be no assurance that an agreement will be reached.

On September 30 and November 7, 2016, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately 3.1% at September 30, 2016. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of September 30, 2016, the bank credit facility was guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”). On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore.

10


 
The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank 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. However, the Amendment provides 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. The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank 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 bank credit facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.5 to 1. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of September 30, 2016.

Senior Notes. Our senior notes consist of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the Bankruptcy Code on or before December 9, 2016 to implement the Plan (see Note 16 – Subsequent Events).

2017 Convertible Notes. On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “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 $1,000 principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately $42.65 per share of our common stock at the time of the issuance of the 2017 Convertible Notes. 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. 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. Prior to December 1, 2016, the 2017 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the second scheduled trading day immediately preceding the maturity date. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock (see Note 1 – Interim Financial Statements). 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 September 30, 2016, our closing share price was $11.88 per share.

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 1and September 1. On the maturity date, each holder will be entitled to receive $1,000 in cash for each $1,000 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 $70.8 million 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 $40.1 million 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.
 

11


As of September 30, 2016, the carrying amount of the liability component of the 2017 Convertible Notes of $292.4 million was classified as a current liability. During the three and nine months ended September 30, 2016, we recognized $4.1 million and $12.0 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $1.1 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine months ended September 30, 2015, we recognized $3.8 million and $11.1 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $1.1 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine month periods ended September 30, 2016, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and nine month periods ended September 30, 2015, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

2022 Notes. On November 8, 2012 and November 27, 2013, respectively, we completed the public offering of $300 million and $475 million aggregate principal amount of our 2022 Notes. The 2022 Notes mature on November 15, 2022. We have an interest payment obligation under our 2022 Notes of approximately $29.2 million, due on November 15, 2016. The indenture governing the 2022 Notes provides a 30-day grace period that extends 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.

Note 6 – Asset Retirement Obligations
 
The change in our asset retirement obligations during the nine months ended September 30, 2016 is set forth below:
 
Nine Months Ended
September 30, 2016
 
(In millions)
Asset retirement obligations as of the beginning of the period, including current portion
$
225.9

Liabilities incurred
2.1

Liabilities settled
(15.1
)
Accretion expense
30.1

Asset retirement obligations as of the end of the period, including current portion
$
243.0

 
Note 7 – Income Taxes
 
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 September 30, 2016, our valuation allowance totaled $343.1 million. Our effective tax rate for the nine months ended September 30, 2016 was 1.4%. This percentage differed from the federal statutory rate of 35.0% primarily due to the establishment of the valuation allowance against deferred tax assets. 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. We had a current income tax receivable of $19.9 million at September 30, 2016, which relates to expected tax refunds from the carryback of net operating losses to previous tax years. Additionally, we had $4.7 million of non-current income tax receivables at September 30, 2016 reflected in Other Assets, as the refunds are not expected to be received within twelve months.

Note 8 – Fair Value Measurements
 
U.S. Generally Accepted Accounting Principles establish 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 September 30, 2016 and December 31, 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 contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs

12


used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see Note 4 – 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 September 30, 2016 and December 31, 2015. The following tables present our assets that are measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015.
 
Fair Value Measurements at
 
September 30, 2016
Assets
Total
 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(In millions)
Marketable securities (Other assets)
$
8.8

 
$
8.8

 
$
—

 
$
—

Derivative contracts
6.3

 
—

 
6.3

 
—

Total
$
15.1

 
$
8.8

 
$
6.3

 
$
—

 
 
 
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)
 
(In millions)
Marketable securities (Other assets)
$
8.5

 
$
8.5

 
$
—

 
$
—

Derivative contracts
38.6

 
—

 
36.6

 
2.0

Total
$
47.1

 
$
8.5

 
$
36.6

 
$
2.0

  
The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2016.
 
 
Hedging Contracts, net
 
 
(In millions)
Balance as of January 1, 2016
 
$
2.0

Total gains/(losses) (realized or unrealized):
 
 
Included in earnings
 
1.1

Included in other comprehensive income
 
(1.9
)
Purchases, sales, issuances and settlements
 
(1.2
)
Transfers in and out of Level 3
 
—

Balance as of September 30, 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 September 30, 2016
 
$
—

The fair value of cash and cash equivalents approximated book value at September 30, 2016 and December 31, 2015. As of September 30, 2016 and December 31, 2015, the fair value of the liability component of the 2017 Convertible Notes was approximately $278.6 million and $217.1 million, respectively. As of September 30, 2016 and December 31, 2015, the fair value of the 2022 Notes was approximately $441.8 million and $271.3 million, respectively.

13


 
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 5 – Debt) at inception, September 30, 2016 and December 31, 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 – Accumulated Other Comprehensive Income (Loss)
 
For the three months ended September 30, 2016, the only component of accumulated other comprehensive income (loss) related to our cash flow hedges. Changes in accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2016, were as follows (in millions):
 
Cash Flow
Hedges
 
 
Three Months Ended September 30, 2016
 
 
 
Beginning balance, net of tax
$
7.4

 
 
Other comprehensive income (loss) before reclassifications:
 
 
 
Change in fair value of derivatives
2.3

 
 
Income tax effect
(0.8
)
 
 
Net of tax
1.5

 
 
Amounts reclassified from accumulated other comprehensive income:
 
 
 
Operating revenue: oil/natural gas production
7.7

 
 
Income tax effect
(2.7
)
 
 
Net of tax
5.0

 
 
Other comprehensive loss, net of tax
(3.5
)
 
 
Ending balance, net of tax
$
3.9

 
 

 
Cash Flow
Hedges
 
Foreign
Currency
Items
 
Total
Nine Months Ended September 30, 2016
 
 
 
 
 
Beginning balance, net of tax
$
24.0

 
$
(6.0
)
 
$
18.0

Other comprehensive income (loss) before reclassifications:
 
 
 
 
 
Change in fair value of derivatives
(1.7
)
 
—

 
(1.7
)
Income tax effect
0.6

 
—

 
0.6

Net of tax
(1.1
)
 
—

 
(1.1
)
Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
Operating revenue: oil/natural gas production
29.4

 
—

 
29.4

Other operational expenses
—

 
(6.0
)
 
(6.0
)
Income tax effect
(10.4
)
 
—

 
(10.4
)
Net of tax
19.0

 
(6.0
)
 
13.0

Other comprehensive income (loss), net of tax
(20.1
)
 
6.0

 
(14.1
)
Ending balance, net of tax
$
3.9

 
$
—

 
$
3.9



14


Changes in accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2015, were as follows (in millions):
 
Cash Flow
Hedges
 
Foreign
Currency
Items
 
Total
Three Months Ended September 30, 2015
 
 
 
 
 
Beginning balance, net of tax
$
46.5

 
$
(5.8
)
 
$
40.7

Other comprehensive income (loss) before reclassifications:
 
 
 
 
 
Change in fair value of derivatives
31.6

 
—

 
31.6

Foreign currency translations
—

 
(0.2
)
 
(0.2
)
Income tax effect
(11.5
)
 
—

 
(11.5
)
Net of tax
20.1

 
(0.2
)
 
19.9

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
Operating revenue: oil/natural gas production
39.9

 
—

 
39.9

Income tax effect
(14.4
)
 
—

 
(14.4
)
Net of tax
25.5

 
—

 
25.5

Other comprehensive loss, net of tax
(5.4
)
 
(0.2
)
 
(5.6
)
Ending balance, net of tax
$
41.1

 
$
(6.0
)
 
$
35.1

 
 
Cash Flow
Hedges
 
Foreign
Currency
Items
 
Total
Nine Months Ended September 30, 2015
 
 
 
 
 
Beginning balance, net of tax
$
86.8

 
$
(3.5
)
 
$
83.3

Other comprehensive income (loss) before reclassifications:
 
 
 
 
 
Change in fair value of derivatives
35.7

 
—

 
35.7

Foreign currency translations
—

 
(2.5
)
 
(2.5
)
Income tax effect
(12.8
)
 
—

 
(12.8
)
Net of tax
22.9

 
(2.5
)
 
20.4

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
Operating revenue: oil/natural gas production
107.1

 
—

 
107.1

Income tax effect
(38.5
)
 
—

 
(38.5
)
Net of tax
68.6

 
—

 
68.6

Other comprehensive loss, net of tax
(45.7
)
 
(2.5
)
 
(48.2
)
Ending balance, net of tax
$
41.1

 
$
(6.0
)
 
$
35.1


During the nine months ended September 30, 2016, we reclassified approximately $6.0 million of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC.

Note 10 – Investment in Oil and Gas Properties
 
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 September 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36.5 million based on twelve-month average prices, net of applicable differentials, of $40.51 per Bbl of oil, $1.99 per Mcf of natural gas and $13.88 per Bbl of natural gas liquids ("NGLs"). The write-down at September 30, 2016 was decreased by $9.6 million as a result of hedges. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118.6 million 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. The write-down at June 30, 2016 was decreased by $18.1 million as a result of hedges. At March 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128.9 million 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

15


$0.3 million related to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. The write-down at March 31, 2016 was decreased by $23 million as a result of hedges.

Note 11 – Other Operational Expenses

Included in other operational expenses for the nine months ended September 30, 2016 is a $6.0 million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 9 – Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the nine months ended September 30, 2016 are approximately $15.3 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20 million charge related to the termination of our deep water drilling rig contract with Ensco and $7.5 million in charges related to the terminations of the Appalachian drilling rig contract and a contract with an offshore vessel provider.
Note 12 – Restructuring Fees
In March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We have been engaged in negotiations with financial advisors for certain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and in June 2016, we secured an amendment to our existing credit facility with our bank group. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. We have also been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility. The legal and financial advisory costs associated with these restructuring efforts are included in the statement of operations as restructuring fees and totaled $5.8 million and $16.2 million for the three and nine months ended September 30, 2016, respectively.
Note 13 – 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 million. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $139 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. We have submitted our tailored plan to BOEM and are awaiting its review and approval.

Additionally, on July 14, 2016, BOEM issued a Notice to Lessees (“NTL”) that augments requirements for the posting of additional financial assurances by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency's past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength. Instead, BOEM will allow companies to “self-insure”, but only up to 10% of a company’s “tangible net worth”, which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. 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). BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans. 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 will be required, and we intend to work with BOEM to adjust our previously submitted tailored plan for the provision of new financial assurances required to be posted as a result of the new NTL. Our revised proposed plan would require approximately $35 million to $40 million of incremental financial assurance or bonding for 2016 through 2017, a portion of which may require cash collateral. Under the revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM.


16


Note 14 – Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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. The standard 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.

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments" to reduce diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2017, and 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 2016-15 in the same period, and any adjustments should be reflected as of the beginning of the fiscal year that includes that interim 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 15 – 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 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual.

At the close of business on June 10, 2016, we effected a 1-for-10 reverse stock split (see Note 1 – Interim Financial Statements) 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 million 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 million, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting, 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 procedures. Upon a delisting from the NYSE, we would commence trading on the OTC Pink. 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. We expect to submit our third quarter 2016 plan update to the NYSE by mid-December.

Note 16 – Subsequent Events

Restructuring Support Agreement

On October 20, 2016, the Company entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that the Company will file for voluntary relief under chapter 11 of the Bankruptcy Code in a Bankruptcy Court on or before December 9, 2016 to implement the Plan in accordance with the term sheet annexed to the RSA (the “Term Sheet”).

The RSA would become effective upon (i) execution by the Company and Noteholders holding, in the aggregate, at least two-thirds of the outstanding aggregate principal amount of the Notes, and (ii) Stone having entered into a PSA for the sale of Properties for a cash

17


purchase price of at least $350 million. Both conditions were satisfied, with Noteholders holding approximately 85.4% of the aggregate principal amount of the Notes executing the RSA and Stone signing the PSA, as indicated below. Pursuant to the terms of the RSA and the Term Sheet, Noteholders and other interest holders will receive treatment under the Plan summarized as follows:
•
The Noteholders will receive their pro rata share of (a) $150 million of the net cash proceeds from the sale of the Properties plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any, (b) 95% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022.

•
Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants.

•
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. Stone estimates that such unsecured claims are in the range of approximately $17 million to $27 million in the aggregate.

•
Holders of claims arising on account of Stone’s existing revolving credit facility will receive (a)(i) if such holders vote, as a class, to accept the Plan, commitments on terms set forth on Exhibit 1(a) to the Term Sheet, on a pro rata basis, under an amended revolving credit facility, or (ii) if such holders, as a class, do not vote to accept the Plan (or are deemed to reject the Plan), a term loan on terms set forth on Exhibit 1(b) to the Term Sheet, or (b) such other treatment as is acceptable to the Company and the Noteholders and consistent with the Bankruptcy Code, including, but not limited to, section 1129(b) of the Bankruptcy Code.

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.

The Company has been engaged in discussions and has exchanged proposals with the lenders under its bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached.  While the Company expects to continue discussions and related negotiations with the lenders under its bank credit facility, there can be no assurance that an agreement will be reached.
The RSA contains certain covenants on the part of the Company and the Noteholders who are signatories to the RSA, including that such Noteholders will vote in favor of the Plan, support the sale of the Properties and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the RSA. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by Stone of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. The RSA also provides for termination by each party, or by either party, upon the occurrence of certain events, including without limitation, termination by the Noteholders upon the failure of the Company to achieve certain milestones set forth in Schedule 1 to the RSA.
 
Assuming implementation of the Plan, Stone expects that it will eliminate approximately $850 million in principal of outstanding debt and reduce its annual interest payment burden by approximately $46 million.

On November 4, 2016 the Company and the Noteholders entered into the RSA Amendment pursuant to which:

•
Stone will be obligated to, at any time upon the written request of the Noteholders or their counsel, provide in writing to counsel to the Noteholders the good faith estimate of Stone – together with documentation requested by the Noteholders or their counsel – of any cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases on both a “per contract” basis and in the aggregate;

•
The Noteholders will have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all such payments exceeds an amount acceptable to the Noteholders;

•
The Noteholders will have the unilateral right to extend the automatic termination of the RSA if the restructuring transactions contemplated by the RSA are not consummated by the one-hundredth (100th) calendar day after the Company files for chapter 11 bankruptcy; and

•
Solicitation of noteholders in support of the Plan will commence by November 10, 2016.

Although the Company intends to pursue the restructuring in accordance with the terms set forth in the RSA and the RSA Amendment, there can be no assurance that the Company will be successful in completing a restructuring or any other similar transaction on the terms set forth in the RSA and the RSA Amendment, on different terms or at all.

18



Purchase and Sale Agreement

On October 20, 2016 (the “Execution Date”), Stone entered into the PSA with Tug Hill. Pursuant to the terms of the PSA, Stone agreed to sell the Properties to Tug Hill (the “Disposition”) for $360 million in cash, subject to customary purchase price adjustments (the “Purchase Price”).

The Disposition has an effective date of June 1, 2016. In connection with the execution of the PSA, Tug Hill deposited $5.0 million in escrow, which amount may be supplemented by an additional $31 million at a later date on certain conditions being met. Upon a closing, the deposit will be credited against the Purchase Price. From the Execution Date through December 19, 2016 (the “Diligence Period”), Tug Hill intends to conduct customary due diligence to assess the aggregate dollar value of any title and environmental defects associated with the Properties. The parties expect to close the Disposition by February 25, 2017, subject to customary closing conditions and approval by the Bankruptcy Court.

The PSA contains customary representations, warranties and covenants. From and after the closing of the Disposition, Stone and Tug Hill, 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 PSA, subject to certain customary limitations and survival periods. Additionally, from and after closing of the Disposition, Stone has agreed to indemnify Tug Hill for certain identified retained liabilities related to the Properties, subject to certain survival periods, and Tug Hill has agreed to indemnify Stone for certain assumed obligations related to the Properties.

The 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, (iv) if, on or prior to the end of the Diligence Period, title and environmental defect amounts (after application of customary thresholds and deductibles), casualty losses and the value of any assets excluded from the Properties due to the exercise of preferential purchase rights or consents equal or exceed $10 million in the aggregate, (v) if Stone fails to file for bankruptcy on or before December 9, 2016, (vi) if the Bankruptcy Court does not enter an order approving Stone’s assumption of the PSA and certain other matters within 30 days of Stone filing for bankruptcy, (vii) if the Bankruptcy Court does not enter a sale order for the Disposition by February 10, 2017, and (viii) upon the occurrence of certain other events specified in the PSA.

Note 17 – 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 unaudited condensed consolidating financial information as of September 30, 2016 and December 31, 2015 and for the three and nine month periods ended September 30, 2016 and 2015 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

19



CONDENSED CONSOLIDATING BALANCE SHEET
SEPTEMBER 30, 2016
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
152,384

 
$
30,015

 
$
—

 
$
—

 
$
182,399

Accounts receivable
17,336

 
40,736

 
883

 
(14,892
)
 
44,063

Fair value of derivative contracts
—

 
6,261

 
—

 
—

 
6,261

Current income tax receivable
19,863

 
—

 
—

 
—

 
19,863

Other current assets
11,176

 
—

 
—

 
—

 
11,176

Total current assets
200,759

 
77,012

 
883

 
(14,892
)
 
263,762

Oil and gas properties, full cost method:
 
 
 
 
 
 
 
 
 
Proved
1,932,435

 
7,586,930

 
45,196

 
—

 
9,564,561

Less: accumulated DD&A
(1,932,640
)
 
(7,076,233
)
 
(45,196
)
 
—

 
(9,054,069
)
Net proved oil and gas properties
(205
)
 
510,697

 
—

 
—

 
510,492

Unevaluated
261,101

 
143,125

 
—

 
—

 
404,226

Other property and equipment, net
27,227

 
—

 
—

 
—

 
27,227

Other assets, net
28,852

 
948

 
—

 
—

 
29,800

Investment in subsidiary
480,971

 
—

 
—

 
(480,971
)
 
—

Total assets
$
998,705

 
$
731,782

 
$
883

 
$
(495,863
)

$
1,235,507

Liabilities and Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable to vendors
$
35,189

 
$
8,963

 
$
—

 
$
(14,893
)
 
$
29,259

Undistributed oil and gas proceeds
6,535

 
904

 
—

 
—

 
7,439

Accrued interest
22,917

 
—

 
—

 
—

 
22,917

Asset retirement obligations
—

 
60,223

 
—

 
—

 
60,223

Current portion of long-term debt
292,795

 
—

 
—

 
—

 
292,795

Other current liabilities
10,778

 
125

 
—

 
—

 
10,903

Total current liabilities
368,214

 
70,215

 
—

 
(14,893
)
 
423,536

Long-term debt
1,122,945

 
—

 
—

 
—

 
1,122,945

Asset retirement obligations
1,336

 
181,480

 
—

 
—

 
182,816

Other long-term liabilities
25,871

 
—

 
—

 
—

 
25,871

Total liabilities
1,518,366

 
251,695

 
—

 
(14,893
)
 
1,755,168

Commitments and contingencies

 

 

 

 

Stockholders’ equity:
 
 
 
 
 
 
 
 
 
Common stock
56

 
—

 
—

 
—

 
56

Treasury stock
(860
)
 
—

 
—

 
—

 
(860
)
Additional paid-in capital
1,657,028

 
1,344,577

 
109,079

 
(1,453,656
)
 
1,657,028

Accumulated deficit
(2,179,803
)
 
(868,408
)
 
(108,196
)
 
976,604

 
(2,179,803
)
Accumulated other comprehensive income
3,918

 
3,918

 
—

 
(3,918
)
 
3,918

Total stockholders’ equity
(519,661
)
 
480,087

 
883

 
(480,970
)
 
(519,661
)
Total liabilities and stockholders’ equity
$
998,705

 
$
731,782

 
$
883

 
$
(495,863
)
 
$
1,235,507


20


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



21


CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2016
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Operating revenue:
 
 
 
 
 
 
 
 
 
Oil production
$
3,587

 
$
67,529

 
$
—

 
$
—

 
$
71,116

Natural gas production
7,216

 
8,385

 
—

 
—

 
15,601

Natural gas liquids production
5,737

 
929

 
—

 
—

 
6,666

Other operational income
1,044

 
—

 
—

 
—

 
1,044

Total operating revenue
17,584

 
76,843

 
—

 
—

 
94,427

Operating expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
2,771

 
14,205

 
—

 
—

 
16,976

Transportation, processing and gathering expenses
9,607

 
1,026

 
—

 
—

 
10,633

Production taxes
669

 
166

 
—

 
—

 
835

Depreciation, depletion and amortization
26,388

 
32,530

 
—

 
—

 
58,918

Write-down of oil and gas properties
1

 
36,483

 
—

 
—

 
36,484

Accretion expense
58

 
10,024

 
—

 
—

 
10,082

Salaries, general and administrative expenses
15,425

 
—

 
—

 
—

 
15,425

Incentive compensation expense
2,160

 
—

 
—

 
—

 
2,160

Restructuring fees
5,784

 
—

 
—

 
—

 
5,784

Other operational expenses
9,214

 
(155
)
 
—

 
—

 
9,059

Derivative expense, net
—

 
199

 
—

 
—

 
199

Total operating expenses
72,077

 
94,478

 
—

 
—

 
166,555

Loss from operations
(54,493
)
 
(17,635
)
 
—

 
—

 
(72,128
)
Other (income) expenses:
 
 
 
 
 
 
 
 
 
Interest expense
16,924

 
—

 
—

 
—

 
16,924

Interest income
(43
)
 
(15
)
 
—

 
—

 
(58
)
Other income
(64
)
 
(208
)
 
—

 
—

 
(272
)
Other expense
16

 
—

 
—

 
—

 
16

Loss from investment in subsidiaries
19,300

 
—

 
1

 
(19,301
)
 
—

Total other (income) expenses
36,133

 
(223
)
 
1

 
(19,301
)
 
16,610

Loss before taxes
(90,626
)
 
(17,412
)
 
(1
)
 
19,301

 
(88,738
)
Provision (benefit) for income taxes:
 
 
 
 
 
 
 
 
 
Current
(991
)
 
—

 
—

 
—

 
(991
)
Deferred
—

 
1,888

 
—

 
—

 
1,888

Total income taxes
(991
)
 
1,888

 
—

 
—

 
897

Net loss
$
(89,635
)
 
$
(19,300
)
 
$
(1
)
 
$
19,301

 
$
(89,635
)
Comprehensive loss
$
(93,102
)
 
$
(19,300
)
 
$
(1
)
 
$
19,301

 
$
(93,102
)


22


CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2015
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Operating revenue:
 
 
 
 
 
 
 
 
 
Oil production
$
1,633

 
$
103,380

 
$
—

 
$
—

 
$
105,013

Natural gas production
7,111

 
10,256

 
—

 
—

 
17,367

Natural gas liquids production
3,502

 
2,478

 
—

 
—

 
5,980

Other operational income
1,392

 
—

 
—

 
—

 
1,392

Derivative income, net
—

 
2,444

 
—

 
—

 
2,444

Total operating revenue
13,638

 
118,558

 
—

 
—

 
132,196

Operating expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
2,680

 
21,562

 
2

 
—

 
24,244

Transportation, processing and gathering expenses
13,697

 
4,511

 
—

 
—

 
18,208

Production taxes
1,777

 
275

 
—

 
—

 
2,052

Depreciation, depletion and amortization
27,518

 
34,418

 
—

 
—

 
61,936

Write-down of oil and gas properties
295,679

 
—

 
—

 
—

 
295,679

Accretion expense
92

 
6,406

 
—

 
—

 
6,498

Salaries, general and administrative expenses
19,348

 
200

 
4

 
—

 
19,552

Incentive compensation expense
794

 
—

 
—

 
—

 
794

Other operational expenses
142

 
300

 
—

 
—

 
442

Total operating expenses
361,727

 
67,672

 
6

 
—

 
429,405

Income (loss) from operations
(348,089
)
 
50,886

 
(6
)
 
—

 
(297,209
)
Other (income) expenses:
 
 
 
 
 
 
 
 
 
Interest expense
10,871

 
1

 
—

 
—

 
10,872

Interest income
(39
)
 
(7
)
 
(1
)
 
—

 
(47
)
Other income
(117
)
 
(294
)
 
—

 
—

 
(411
)
Other expense
148

 
—

 
—

 
—

 
148

(Income) loss from investment in subsidiaries
(227,973
)
 
—

 
16,272

 
211,701

 
—

Total other (income) expenses
(217,110
)
 
(300
)
 
16,271

 
211,701

 
10,562

Income (loss) before taxes
(130,979
)
 
51,186

 
(16,277
)
 
(211,701
)
 
(307,771
)
Provision (benefit) for income taxes:
 
 
 
 
 
 
 
 
 
Deferred
160,986

 
(193,059
)
 
16,267

 
—

 
(15,806
)
Total income taxes
160,986

 
(193,059
)
 
16,267

 
—

 
(15,806
)
Net income (loss)
$
(291,965
)
 
$
244,245

 
$
(32,544
)
 
$
(211,701
)
 
$
(291,965
)
Comprehensive income (loss)
$
(297,564
)
 
$
244,245

 
$
(32,544
)
 
$
(211,701
)
 
$
(297,564
)


23


CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2016
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Operating revenue:
 
 
 
 
 
 
 
 
 
Oil production
$
4,971

 
$
199,131

 
$
—

 
$
—

 
$
204,102

Natural gas production
13,642

 
29,685

 
—

 
—

 
43,327

Natural gas liquids production
9,246

 
5,873

 
—

 
—

 
15,119

Other operational income
1,737

 
—

 
—

 
—

 
1,737

Total operating revenue
29,596

 
234,689

 
—

 
—

 
264,285

Operating expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
9,313

 
46,023

 
13

 
—

 
55,349

Transportation, processing and gathering expenses
17,174

 
1,483

 
—

 
—

 
18,657

Production taxes
1,311

 
583

 
—

 
—

 
1,894

Depreciation, depletion and amortization
45,452

 
121,255

 
—

 
—

 
166,707

Write-down of oil and gas properties
15,859

 
268,128

 
350

 
—

 
284,337

Accretion expense
174

 
29,973

 
—

 
—

 
30,147

Salaries, general and administrative expenses
48,392

 
(199
)
 
—

 
—

 
48,193

Incentive compensation expense
11,809

 
—

 
—

 
—

 
11,809

Restructuring fees
16,173

 
—

 
—

 
—

 
16,173

Other operational expenses
43,059

 
125

 
6,082

 
—

 
49,266

Derivative expense, net
—

 
687

 
—

 
—

 
687

Total operating expenses
208,716

 
468,058

 
6,445

 
—

 
683,219

Loss from operations
(179,120
)
 
(233,369
)
 
(6,445
)
 
—

 
(418,934
)
Other (income) expenses:
 
 
 
 
 
 
 
 
 
Interest expense
49,764

 
—

 
—

 
—

 
49,764

Interest income
(459
)
 
(15
)
 
—

 
—

 
(474
)
Other income
(123
)
 
(717
)
 
—

 
—

 
(840
)
Other expense
27

 
—

 
—

 
—

 
27

Loss from investment in subsidiaries
250,029

 
—

 
6,445

 
(256,474
)
 
—

Total other (income) expenses
299,238

 
(732
)
 
6,445

 
(256,474
)
 
48,477

Loss before taxes
(478,358
)
 
(232,637
)
 
(12,890
)
 
256,474

 
(467,411
)
Provision (benefit) for income taxes:
 
 
 
 
 
 
 
 
 
Current
(4,178
)
 
—

 
—

 
—

 
(4,178
)
Deferred
—

 
10,947

 
—

 
—

 
10,947

Total income taxes
(4,178
)
 
10,947

 
—

 
—

 
6,769

Net loss
$
(474,180
)
 
$
(243,584
)
 
$
(12,890
)
 
$
256,474

 
$
(474,180
)
Comprehensive loss
$
(488,214
)
 
$
(243,584
)
 
$
(12,890
)
 
$
256,474

 
$
(488,214
)


24


CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2015
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Operating revenue:
 
 
 
 
 
 
 
 
 
Oil production
$
12,487

 
$
311,618

 
$
—

 
$
—

 
$
324,105

Natural gas production
39,375

 
33,236

 
—

 
—

 
72,611

Natural gas liquids production
21,458

 
7,921

 
—

 
—

 
29,379

Other operational income
3,184

 
—

 
—

 
—

 
3,184

Derivative income, net
—

 
4,871

 
—

 
—

 
4,871

Total operating revenue
76,504

 
357,646

 
—

 
—

 
434,150

Operating expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
12,767

 
66,481

 
2

 
—

 
79,250

Transportation, processing and gathering expenses
47,779

 
8,072

 
—

 
—

 
55,851

Production taxes
5,411

 
983

 
—

 
—

 
6,394

Depreciation, depletion and amortization
113,682

 
112,627

 
—

 
—

 
226,309

Write-down of oil and gas properties
966,216

 
—

 
45,169

 
—

 
1,011,385

Accretion expense
274

 
19,041

 
—

 
—

 
19,315

Salaries, general and administrative expenses
52,747

 
201

 
29

 
—

 
52,977

Incentive compensation expense
3,621

 
—

 
—

 
—

 
3,621

Other operational expenses
1,312

 
300

 
—

 
—

 
1,612

Total operating expenses
1,203,809

 
207,705

 
45,200

 
—

 
1,456,714

Income (loss) from operations
(1,127,305
)
 
149,941

 
(45,200
)
 
—

 
(1,022,564
)
Other (income) expenses:
 
 
 
 
 
 
 
 
 
Interest expense
31,687

 
22

 
—

 
—

 
31,709

Interest income
(186
)
 
(42
)
 
(7
)
 
—

 
(235
)
Other income
(437
)
 
(727
)
 
(3
)
 
—

 
(1,167
)
Other expense
148

 
—

 
—

 
—

 
148

(Income) loss from investment in subsidiaries
(273,147
)
 
—

 
45,190

 
227,957

 
—

Total other (income) expenses
(241,935
)
 
(747
)
 
45,180

 
227,957

 
30,455

Income (loss) before taxes
(885,370
)
 
150,688

 
(90,380
)
 
(227,957
)
 
(1,053,019
)
Provision (benefit) for income taxes:
 
 
 
 
 
 
 
 
 
Deferred
(113,111
)
 
(167,649
)
 
—

 
—

 
(280,760
)
Total income taxes
(113,111
)
 
(167,649
)
 
—

 
—

 
(280,760
)
Net income (loss)
$
(772,259
)
 
$
318,337

 
$
(90,380
)
 
$
(227,957
)
 
$
(772,259
)
Comprehensive income (loss)
$
(820,517
)
 
$
318,337

 
$
(90,380
)
 
$
(227,957
)
 
$
(820,517
)


25


CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2016
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
Net loss
$
(474,180
)
 
$
(243,584
)
 
$
(12,890
)
 
$
256,474

 
$
(474,180
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
45,452

 
121,255

 
—

 
—

 
166,707

Write-down of oil and gas properties
15,859

 
268,128

 
350

 
—

 
284,337

Accretion expense
174

 
29,973

 
—

 
—

 
30,147

Deferred income tax provision
—

 
10,947

 
—

 
—

 
10,947

Settlement of asset retirement obligations
(78
)
 
(14,129
)
 
(899
)
 
—

 
(15,106
)
Non-cash stock compensation expense
6,407

 
—

 
—

 
—

 
6,407

Non-cash derivative expense
—

 
1,261

 
—

 
—

 
1,261

Non-cash interest expense
14,278

 
—

 
—

 
—

 
14,278

Other non-cash expense
—

 
—

 
6,081

 
—

 
6,081

Change in current income taxes
21,584

 
—

 
—

 
—

 
21,584

Non-cash loss from investment in subsidiaries
250,029

 
—

 
6,445

 
(256,474
)
 
—

Change in intercompany receivables/payables
(1,658
)
 
1,658

 
—

 
—

 
—

(Increase) decrease in accounts receivable
7,966

 
(3,116
)
 
(882
)
 
—

 
3,968

(Increase) decrease in other current assets
(4,459
)
 
—

 
33

 
—

 
(4,426
)
Increase (decrease) in accounts payable
7,385

 
(4,168
)
 
—

 
—

 
3,217

Decrease in other current liabilities
(13,924
)
 
(298
)
 
—

 
—

 
(14,222
)
Other
(7,389
)
 
(718
)
 
—

 
—

 
(8,107
)
Net cash (used in) provided by operating activities
(132,554
)
 
167,209

 
(1,762
)
 
—

 
32,893

Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Investment in oil and gas properties
(63,075
)
 
(137,196
)
 
(351
)
 
—

 
(200,622
)
Investment in fixed and other assets
(1,231
)
 
—

 
—

 
—

 
(1,231
)
Change in restricted funds
—

 
—

 
1,046

 
—

 
1,046

Investment in subsidiaries
—

 
—

 
716

 
(716
)
 
—

Net cash (used in) provided by investing activities
(64,306
)
 
(137,196
)
 
1,411

 
(716
)
 
(200,807
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from bank borrowings
477,000

 
—

 
—

 
—

 
477,000

Repayments of bank borrowings
(135,500
)
 
—

 
—

 
—

 
(135,500
)
Repayments of building loan
(285
)
 
—

 
—

 
—

 
(285
)
Deferred financing costs
(900
)
 
—

 
—

 
—

 
(900
)
Equity proceeds from parent
—

 
—

 
(716
)
 
716

 
—

Net payments for share-based compensation
(752
)
 
—

 
—

 
—

 
(752
)
Net cash provided by (used in) financing activities
339,563

 
—

 
(716
)

716


339,563

Effect of exchange rate changes on cash
—

 
—

 
(9
)
 
—

 
(9
)
Net change in cash and cash equivalents
142,703

 
30,013

 
(1,076
)
 
—

 
171,640

Cash and cash equivalents, beginning of period
9,681

 
2

 
1,076

 
—

 
10,759

Cash and cash equivalents, end of period
$
152,384

 
$
30,015

 
$
—

 
$
—

 
$
182,399


26


CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2015
(In thousands)
 
Parent
 
Guarantor
Subsidiary
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(772,259
)
 
$
318,337

 
$
(90,380
)
 
$
(227,957
)
 
$
(772,259
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
113,682

 
112,627

 
—

 
—

 
226,309

Write-down of oil and gas properties
966,216

 
—

 
45,169

 
—

 
1,011,385

Accretion expense
274

 
19,041

 
—

 
—

 
19,315

Deferred income tax benefit
(113,111
)
 
(167,649
)
 
—

 
—

 
(280,760
)
Settlement of asset retirement obligations
(15
)
 
(59,811
)
 
—

 
—

 
(59,826
)
Non-cash stock compensation expense
9,163

 
—

 
—

 
—

 
9,163

Non-cash derivative expense
—

 
10,854

 
—

 
—

 
10,854

Non-cash interest expense
13,210

 
—

 
—

 
—

 
13,210

Change in current income taxes
7,211

 
—

 
—

 
—

 
7,211

Non-cash (income) expense from investment in subsidiaries
(273,147
)
 
—

 
45,190

 
227,957

 
—

Change in intercompany receivables/payables
31,320

 
(41,056
)
 
9,736

 
—

 
—

Decrease in accounts receivable
29,561

 
4,317

 
17

 
—

 
33,895

Increase in other current assets
(1,050
)
 
—

 
(40
)
 
—

 
(1,090
)
(Increase) decrease in inventory
(2,415
)
 
2,415

 
—

 
—

 
—

Decrease in accounts payable
(7,562
)
 
(4,030
)
 
—

 
—

 
(11,592
)
Increase (decrease) in other current liabilities
(6,855
)
 
102

 
—

 
—

 
(6,753
)
Other
645

 
(727
)
 
—

 
—

 
(82
)
Net cash (used in) provided by operating activities
(5,132
)
 
194,420

 
9,692

 
—

 
198,980

Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Investment in oil and gas properties
(177,497
)
 
(197,471
)
 
(10,560
)
 
—

 
(385,528
)
Proceeds from sale of oil and gas properties, net of expenses
—

 
11,643

 
—

 
—

 
11,643

Investment in fixed and other assets
(1,455
)
 
—

 
—

 
—

 
(1,455
)
Change in restricted funds
177,647

 
—

 
1,828

 
—

 
179,475

Investment in subsidiaries
—

 
—

 
(9,708
)
 
9,708

 
—

Net cash used in investing activities
(1,305
)
 
(185,828
)
 
(18,440
)
 
9,708

 
(195,865
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from bank borrowings
5,000

 
—

 
—

 
—

 
5,000

Repayments of bank borrowings
(5,000
)
 
—

 
—

 
—

 
(5,000
)
Equity proceeds from parent
—

 
—

 
9,708

 
(9,708
)
 
—

Net payments for share-based compensation
(3,127
)
 
—

 
—

 
—

 
(3,127
)
Net cash (used in) provided by financing activities
(3,127
)
 
—

 
9,708

 
(9,708
)
 
(3,127
)
Effect of exchange rate changes on cash
—

 
—

 
(2
)
 
—

 
(2
)
Net change in cash and cash equivalents
(9,564
)
 
8,592

 
958

 
—

 
(14
)
Cash and cash equivalents, beginning of period
72,886

 
1,450

 
152

 
—

 
74,488

Cash and cash equivalents, end of period
$
63,322

 
$
10,042

 
$
1,110

 
$
—

 
$
74,474


27


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
The information in this Quarterly Report on Form 10-Q (this “Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our 2015 Annual Report on Form 10-K and in this Form 10-Q.
Forward-looking statements may appear in a number of places in this Form 10-Q and include statements with respect to, among other things:

•
expected results from risk-weighted drilling success;
•
estimates of our future oil and natural gas production, including estimates of any increases in oil and natural gas production;
•
planned capital expenditures and the availability of capital resources to fund capital expenditures;
•
our outlook on oil and natural gas prices;
•
estimates of our oil and natural gas reserves;
•
any estimates of future earnings growth;
•
the impact of political and regulatory developments;
•
our outlook on the resolution of pending litigation and government inquiry;
•
estimates of the impact of new accounting pronouncements on earnings in future periods;
•
our future financial condition or results of operations and our future revenues and expenses;
•
the outcome of restructuring efforts and asset sales;
•
the amount, nature and timing of any potential acquisition or divestiture transactions;
•
any expected results or benefits associated with our acquisitions;
•
our access to capital and our anticipated liquidity;
•
estimates of future income taxes; and
•
our business strategy and other plans and objectives for future operations.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:
 
•
our ability to consummate the sale of the Properties (defined below) as contemplated by the PSA (defined below);
•
our ability to confirm and consummate a plan of reorganization in accordance with the terms of the RSA and the RSA Amendment (defined below), or alternative restructuring transaction;
•
risks attendant to the bankruptcy process, including the effects thereof on the Company’s business and on the interests of various constituents;
•
the length of time that the Company might be required to operate in bankruptcy and the continued availability of operating capital during the pendency of such proceedings;
•
risks associated with third party motions in any bankruptcy case, which may interfere with the ability to confirm and consummate a plan of reorganization;
•
potential adverse effects of bankruptcy proceedings on the Company’s liquidity or results of operations;
•
increased costs to execute a reorganization;
•
effects of bankruptcy proceedings on the market price on the Company’s common stock and on the Company’s ability to access the capital markets;
•
our ability to maintain our listing on the New York Stock Exchange ("NYSE");
•
commodity price volatility, including further or sustained declines in the prices we receive for our oil and natural gas production;
•
domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;
•
the availability of capital on economic terms to fund our operations, capital expenditures, acquisitions and other obligations;
•
our future level of indebtedness, liquidity, compliance with debt covenants and our ability to continue as a going concern;
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our future financial condition, results of operations, revenues, cash flows and expenses;
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our ability to continue to borrow under our credit facility;
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our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by BOEM;

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declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our bank credit facility and impairments;
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our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
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the impact of a financial crisis on our business operations, financial condition and ability to raise capital;
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the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
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third-party interruption of sales to market;
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inflation;
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lack of availability and cost of goods and services;
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market conditions relating to potential acquisition and divestiture transactions;
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regulatory and environmental risks associated with drilling and production activities, including, for example, compliance with the Bureau of Safety and Environmental Enforcement's recently finalized well control rule;
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our ability to establish operations or production on our acreage prior to the expiration of related leaseholds;
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availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;
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competition in the oil and gas industry;
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our inability to retain and attract key personnel;
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drilling and other operating risks, including the consequences of a catastrophic event;
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unsuccessful exploration and development drilling activities;
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hurricanes and other weather conditions;
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availability, cost and adequacy of insurance coverage;
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adverse effects of changes in applicable tax, environmental, derivatives, permitting, bonding and other regulatory requirements and legislation, as well as agency interpretation and enforcement and judicial decisions regarding the foregoing, including changes affecting our offshore and Appalachian operations;
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uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and
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other risks described in this Form 10-Q.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, Item 1A. Risk Factors, of this Form 10-Q and (2) Part I, Item 1A, of our 2015 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2015 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our 2015 Annual Report on Form 10-K. 
Critical Accounting Estimates
Our 2015 Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:
 
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remaining proved oil and natural gas reserve volumes and the timing of their production;
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estimated costs to develop and produce proved oil and natural gas reserves;
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accruals of exploration costs, development costs, operating costs and production revenue;
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timing and future costs to abandon our oil and gas properties;
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effectiveness and estimated fair value of derivative positions;
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classification of unevaluated property costs;
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capitalized general and administrative costs and interest;
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estimates of fair value in business combinations;
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current and deferred income taxes; and
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contingencies.
This Form 10-Q should be read together with the discussion contained in our 2015 Annual Report on Form 10-K regarding these critical accounting policies.

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Other Factors Affecting Our Business and Financial Results
In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2015 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, regarding our known material risk factors.
Overview
We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. On October 20, 2016, we entered into a purchase and sale agreement to sell all of our Appalachian properties. See “Restructuring Support Agreement” and “Purchase and Sale Agreement” below.
We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016 and shut in our Mary field in Appalachia in September 2015. The lower commodity prices have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of November 7, 2016, we had total indebtedness of $1,428 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $341.5 million outstanding under our bank credit facility and $11.4 million outstanding under our Building Loan.
On March 10, 2016, we borrowed $385 million under our bank credit facility, which at the time, represented substantially all of the undrawn amount on our $500 million borrowing base. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. In June 2016, however, we entered into the Amendment to our bank credit facility which, among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. In addition, the Amendment requires that we maintain minimum liquidity (as defined in the Amendment) of $125.0 million through January 15, 2017, imposes limitations on capital expenditures from June to December 2016 and provides for anti-hoarding cash provisions for amounts in excess of $50.0 million beginning after December 10, 2016. Upon execution of the Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time.

As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. See "Liquidity and Capital Resources".

In late June 2016, we terminated our deep water drilling rig contract with Ensco for total consideration of $20 million. Additionally, in late June 2016, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, allowing us to resume production at the Mary field. See "Liquidity and Capital Resources". In August 2016, we paid $7.5 million for the early terminations of an Appalachian drilling rig contract and a contract with an offshore vessel provider.

In April 2016, production from our deep water Amethyst well was shut in to allow for a technical evaluation.  During the first week of November, we initiated acid stimulation work and are intermittently flowing the well while we continue to observe and evaluate the well’s performance.  We have identified potential factors which may explain the reason for the April 2016 pressure decline and ultimate production shut in.  If the well continues to perform, we expect to flow and evaluate the well for an extended period of time at 10-15 MMcf per day, although the gas export pipeline capacity may be temporarily restricted due to a gas plant outage that occurred in late June 2016 as a result of an explosion at the facility. Unsuccessful intervention operations may result in reductions to the well's estimated proved reserve quantities and estimated future net cash flows, which could negatively affect our borrowing base under our credit facility. As of December 31, 2015, Amethyst represented approximately 23% and 26% of our estimated proved reserves quantities and standardized measure of discounted future net cash flows, respectively. 



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Restructuring Support Agreement

On October 20, 2016, the Company entered into a restructuring support agreement (the "RSA") with certain holders of the 2017 Convertible Notes and certain holders of the 2022 Notes (together with the 2017 Convertible Notes, the “Notes” and the holders thereof, the “Noteholders”) to support a restructuring on the terms of a pre-packaged plan of reorganization (the “Plan”). The RSA contemplates that the Company will file for voluntary relief under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in a United States Bankruptcy Court (the “Bankruptcy Court”) on or before December 9, 2016 to implement the Plan in accordance with the term sheet annexed to the RSA (the “Term Sheet”).

The RSA would become effective upon (i) execution by the Company and Noteholders holding, in the aggregate, at least two-thirds of the outstanding aggregate principal amount of the Notes, and (ii) Stone having entered into a PSA for the sale of Properties, defined below, for a cash purchase price of at least $350 million. Both conditions were satisfied, with Noteholders holding approximately 85.4% of the aggregate principal amount of the Notes executing the RSA and Stone signing the PSA, as indicated below. Pursuant to the terms of the RSA and the Term Sheet, Noteholders and other interest holders will receive treatment under the Plan summarized as follows:
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The Noteholders will receive their pro rata share of (a) $150 million of the net cash proceeds from the sale of Stone’s approximately 86,000 net acres in the Appalachia regions of Pennsylvania and West Virginia (the “Properties”) plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any, (b) 95% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022.

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Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants.

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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. Stone estimates that such unsecured claims are in the range of approximately $17 million to $27 million in the aggregate.

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Holders of claims arising on account of Stone’s existing revolving credit facility will receive (a)(i) if such holders vote, as a class, to accept the Plan, commitments on terms set forth on Exhibit 1(a) to the Term Sheet, on a pro rata basis, under an amended revolving credit facility, or (ii) if such holders, as a class, do not vote to accept the Plan (or are deemed to reject the Plan), a term loan on terms set forth on Exhibit 1(b) to the Term Sheet, or (b) such other treatment as is acceptable to the Company and the Noteholders and consistent with the Bankruptcy Code, including, but not limited to, section 1129(b) of the Bankruptcy Code.

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.

The Company has been engaged in discussions and has exchanged proposals with the lenders under its bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached.  While the Company expects to continue discussions and related negotiations with the lenders under its bank credit facility, there can be no assurance that an agreement will be reached.
The RSA contains certain covenants on the part of the Company and the Noteholders who are signatories to the RSA, including that such Noteholders will vote in favor of the Plan, support the sale of the Properties and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the RSA. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by Stone of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. The RSA also provides for termination by each party, or by either party, upon the occurrence of certain events, including without limitation, termination by the Noteholders upon the failure of the Company to achieve certain milestones set forth in Schedule 1 to the RSA.
 
Assuming implementation of the Plan, Stone expects that it will eliminate approximately $850 million in principal of outstanding debt and reduce its annual interest payment burden by approximately $46 million.

On November 4, 2016 the Company and the Noteholders entered into an amendment to the RSA (the “RSA Amendment”) pursuant to which:

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Stone will be obligated to, at any time upon the written request of the Noteholders or their counsel, provide in writing to counsel to the Noteholders the good faith estimate of Stone – together with documentation requested by the Noteholders or their counsel – of any cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases on both a “per contract” basis and in the aggregate;

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•
The Noteholders will have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all such payments exceeds an amount acceptable to the Noteholders;

•
The Noteholders will have the unilateral right to extend the automatic termination of the RSA if the restructuring transactions contemplated by the RSA are not consummated by the one-hundredth (100th) calendar day after the Company files for chapter 11 bankruptcy; and

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Solicitation of noteholders in support of the Plan will commence by November 10, 2016.

Although the Company intends to pursue the restructuring in accordance with the terms set forth in the RSA and the RSA Amendment, there can be no assurance that the Company will be successful in completing a restructuring or any other similar transaction on the terms set forth in the RSA and the RSA Amendment, on different terms or at all.

Purchase and Sale Agreement

On October 20, 2016 (the “Execution Date”), Stone entered into a purchase and sale agreement (the “PSA”) with TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”). Pursuant to the terms of the PSA, Stone agreed to sell the Properties to Tug Hill (the “Disposition”) for $360 million in cash, subject to customary purchase price adjustments (the “Purchase Price”).

The Disposition has an effective date of June 1, 2016. In connection with the execution of the PSA, Tug Hill deposited $5.0 million in escrow, which amount may be supplemented by an additional $31 million at a later date on certain conditions being met. Upon a closing, the deposit will be credited against the Purchase Price. From the Execution Date through December 19, 2016 (the “Diligence Period”), Tug Hill intends to conduct customary due diligence to assess the aggregate dollar value of any title and environmental defects associated with the Properties. The parties expect to close the Disposition by February 25, 2017, subject to customary closing conditions and approval by the Bankruptcy Court.

The PSA contains customary representations, warranties and covenants. From and after the closing of the Disposition, Stone and Tug Hill, 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 PSA, subject to certain customary limitations and survival periods. Additionally, from and after closing of the Disposition, Stone has agreed to indemnify Tug Hill for certain identified retained liabilities related to the Properties, subject to certain survival periods, and Tug Hill has agreed to indemnify Stone for certain assumed obligations related to the Properties.

The 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, (iv) if, on or prior to the end of the Diligence Period, title and environmental defect amounts (after application of customary thresholds and deductibles), casualty losses and the value of any assets excluded from the Properties due to the exercise of preferential purchase rights or consents equal or exceed $10 million in the aggregate, (v) if Stone fails to file for bankruptcy on or before December 9, 2016, (vi) if the Bankruptcy Court does not enter an order approving Stone’s assumption of the PSA and certain other matters within 30 days of Stone filing for bankruptcy, (vii) if the Bankruptcy Court does not enter a sale order for the Disposition by February 10, 2017, and (viii) upon the occurrence of certain other events specified in the PSA.

Upon closing of the Disposition, Stone will no longer have operations or assets in Appalachia. Our Appalachian properties accounted for approximately 1% of our estimated proved oil, natural gas and NGL reserves at December 31, 2015. During 2015, virtually all of our Appalachian reserves were removed from proved reserves due to the effect of reduced Appalachian reserve prices for natural gas and NGLs. Our operating margins in Appalachia remained at relatively low levels during 2015 and through June 2016 as a result of low commodity prices and high midstream costs in the area.

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Known Trends and Uncertainties
Declining Commodity Prices – We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties. For the years ended December 31, 2014 and 2015 and the nine months ended September 30, 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million and $284 million, respectively. If NYMEX commodity prices remain at current levels (approximately $46.67 per Bbl of oil and $2.785 per MMBtu of natural gas), we would expect an increase in the 12-month average price used in estimating the present value of estimated future net cash flows of our proved reserves. Accordingly, we would not expect downward revisions to our estimated proved reserve quantities as a result of pricing that would cause us to recognize an additional ceiling test write-down in the fourth quarter of 2016. However, significant evaluations or impairments of unevaluated costs or other well performance-related revisions affecting proved reserve quantities could cause us to recognize such a write-down.
Bank Credit Facility – The level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million from $300 million and revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to1 for the fiscal quarter ended September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter. See "Liquidity and Capital Resources". We were in compliance with all covenants under the bank credit facility and the indentures governing our outstanding notes as of September 30, 2016. However, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity.
We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached.  While we expect to continue discussions and related negotiations with the lenders under our bank credit facility, there can be no assurance that an agreement will be reached.
If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. The borrowing base under our bank credit facility as of November 7, 2016 was $360 million, a reduction from the borrowing base of $500 million as of April 12, 2016. See "Liquidity and Capital Resources". Continued low commodity prices or further declines in commodity prices could have a further adverse impact on the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.
BOEM Financial Assurance Requirements – The Bureau of Ocean Energy Management ("BOEM") requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565 million. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $139 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. We have submitted our tailored plan to BOEM and are awaiting its review and approval.
Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency's past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength. Instead, BOEM will allow companies to “self-insure”, but only up to 10% of a company’s “tangible net worth”, which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. 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

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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). BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans. 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 will be required, and we intend to work with BOEM to adjust our previously submitted tailored plan for the provision of new financial assurances required to be posted as a result of the new NTL. Our revised proposed plan would require approximately $35 million to $40 million of incremental financial assurance or bonding for 2016 through 2017, a portion of which may require cash collateral. Under the revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.
The new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the outer continental shelf ("OCS"), which will in turn force these operators to seek additional surety bonds and could, consequently, exceed the surety bond market’s current capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.
In addition, although the surety companies have not historically required collateral from us to back our surety bonds, we recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide additional cash collateral on existing and new surety bonds we expect BOEM will require to satisfy their financial assurance requirements. We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds to comply with supplemental bonding requirements of the BOEM. This need to obtain additional surety bonds, or some other form of financial assurances, could impact our liquidity. 
Hurricanes – Since a large portion of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible increases to and/or acceleration of plugging and abandonment costs, all of which could also affect our ability to remain in compliance with the covenants under our bank credit facility.
Deep Water Operations – We are currently operating two significant properties in the deep water of the GOM and engage in deep water drilling operations. Operations in the deep water involve high operational risks. Despite technological advances over the last several years, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant losses on our statement of operations as well as going concern issues.
Liquidity and Capital Resources
Overview.
As of November 7, 2016, the Company’s cash and cash equivalents totaled approximately $181.5 million, and the Company had approximately $1,428 million in total debt outstanding, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $341.5 million outstanding under our bank credit facility and $11.4 million outstanding under our Building Loan.

On April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. At the time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million, and on that date, we repaid $56.8 million in borrowings, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit

34


facility in conformity with the borrowing base limitation. See "Bank Credit Facility" below. As of November 7, 2016, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving approximately $6.0 million of availability under the bank credit facility.
We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017. Additionally, we have an interest obligation under our 2022 Notes of approximately $29.2 million due on November 15, 2016 (see "Senior Notes" below). As a result of continued decreases in commodity prices and the level of our indebtedness, we continue to work with financial and legal advisors to analyze various financial, transactional and strategic alternatives. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the Bankruptcy Code on or before December 9, 2106. See "Overview – Restructuring Support Agreement". Additionally, on October 20, 2016, we entered into a purchase and sale agreement to sell all of our Appalachia properties for $360 million in cash, subject to customary purchase price adjustments. See "Overview – Purchase and Sale Agreement". We cannot provide any assurances that we will be able to complete a restructuring or asset sales on satisfactory terms to provide liquidity to restructure or pay down our senior indebtedness.
Our capital expenditure budget for 2016 was set by the board of directors at $200 million, and assumed success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled, or if unsuccessful, stacking the rig. The farm out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and were expected to range between $40 million and $50 million. During the first two quarters of 2016, we successfully executed two separate rig farm out arrangements for the ENSCO 8503 with other operators. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water drilling rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. To further reduce capital expenditures for 2016, we elected to temporarily stack the Pompano platform drilling rig in place. In addition, during the third quarter of 2016 we terminated an offshore vessel contract and Appalachian rig contract. The updated rig schedule and cost reduction efforts have decreased our projected 2016 capital expenditures to approximately $160 million to $170 million. The 2016 capital expenditure budget excludes material acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest as well as potential subsidy expense associated with rig farm outs, rig stacking charges and termination consideration. As noted above, the rig stacking, subsidy and termination charges were accounted for in other operational expenses and are expected to be approximately $46 million for 2016.

Also, in late June 2016, Stone entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia. The interim agreement provides near-term relief for Stone by permitting Stone to resume profitable production and positive cash flow at the Mary field. The initial term of the interim agreement was through August 31, 2016 and it continues on a month to month basis thereafter unless terminated by either party. Subsequent to the execution of the interim agreement, production from much of the Mary field resumed in late June and averaged over 90 MMcfe per day during the third quarter of 2016, with total Appalachia volumes averaging 112 MMcfe per day during the third quarter of 2016. We expect daily production rates from Appalachia to average 120 MMcfe to 140 MMcfe per day in the fourth quarter of 2016. On October 20, 2016, we entered into a purchase and sale agreement to sell all of our Appalachia properties. See "Overview – Purchase and Sale Agreement".
Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures primarily with cash on hand from borrowings under our bank credit facility and expected cash flows from operating activities. Although our capital expenditure budget for 2017 has not yet been approved and is dependent on the outcome of potential chapter 11 proceedings and the related reorganization of the Company, we currently expect to reinstate drilling operations at Pompano in early 2017. While management believes the Company's expected cash flows from operating activities and cash on hand for 2017 will be adequate to meet the operating needs of the post-reorganized Company, there are no assurances that a chapter 11 plan will be approved by the Bankruptcy Court.
Historically, we have been able to obtain an exemption from supplemental bonding requirements on our offshore leases for abandonment obligations based on financial net worth, however, on March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. We have submitted our tailored plan to BOEM and are awaiting its review and approval.
Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurances by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency's past practice

35


of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength. Instead, BOEM will allow companies to “self-insure”, but only up to 10% of a company’s “tangible net worth”, which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. 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 will be required, and we intend to work with BOEM to adjust our previously submitted tailored plan for the provision of new financial assurances required to be posted as a result of the new NTL. Our revised proposed plan would require approximately $35 million to $40 million of incremental financial assurance or bonding for 2016 through 2017, a portion of which may require cash collateral. Under the revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM.
Although the surety companies have not historically required collateral from us to back our surety bonds, we recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide additional cash collateral on existing and new surety bonds we expect BOEM will require to satisfy their financial assurance requirements. This need to obtain additional surety bonds or some other form of financial assurance, could impact our liquidity. See Known Trends and Uncertainties.
Indebtedness.
Bank Credit Facility – On June 24, 2014, we entered into a revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019 and is guaranteed by our Guarantor Subsidiaries. The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. At that time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016.
On June 14, 2016, we entered into the Amendment to the bank credit facility to (i) increase the borrowing base to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ended September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures from June through December 2016, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the Amendment, we repaid $56.8 million in borrowings under the credit facility, bringing total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. On November 7, 2016, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility.

We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached.  While we expect to continue discussions and related negotiations with the lenders under our bank credit facility, there can be no assurance that an agreement will be reached. Pursuant to the terms of the RSA, if the lenders under our bank credit facility do not vote to accept the Plan (or are deemed to reject the Plan), they will receive, on a pro rata basis, a $342 million exit term loan or such other treatment as is acceptable to Stone and the Noteholders and consistent with the Bankruptcy Code. The exit term loan would have a five year maturity from the effective date of the RSA and would be a first-lien senior secured obligation guaranteed by Stone Offshore, not subject to a borrowing base, to be repaid at any time at par at the election of Stone. The exit term loan would bear interest at the Treasury rate plus 2.00% per annum.

The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Low commodity prices and negative price differentials have had a material adverse impact on the value of our estimated proved reserves and, in turn, the

36


market value used by the lenders to determine our borrowing base. Continued low commodity prices or further declines in commodity prices will likely have a further material adverse impact on the value of our estimated proved reserves.

Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. In addition to the covenants discussed above, the bank credit facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.5 to 1. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes. However, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
Senior Notes – Our senior notes consist of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. 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). We have an interest payment obligation under our 2022 Notes of approximately $29.2 million, due on November 15, 2016. The indenture governing the 2022 Notes provides a 30-day grace period that extends 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. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the United States Bankruptcy Code on or before December 9, 2016. See Overview.
Cash Flow and Working Capital.
Net cash provided by operating activities totaled $32.9 million during the nine months ended September 30, 2016 compared to $199.0 million during the comparable period in 2015. The decrease was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices, the decline in natural gas and NGL production volumes, restructuring fees, rig subsidy and stacking expenses, drilling rig and offshore vessel contract termination fees, partially offset by a decline in lease operating and transportation, processing and gathering ("TP&G") expenses. See "Results of Operations" for additional information relative to commodity prices, production and operating expense variances.
Net cash used in investing activities totaled $200.8 million during the nine months ended September 30, 2016, which primarily represents our investment in oil and gas properties. Net cash used in investing activities totaled $195.9 million during the nine months ended September 30, 2015, which primarily represents our investment in oil and gas properties of $385.5 million, offset by $179.5 million of previously restricted proceeds from the sale of oil and gas properties.
Net cash provided by financing activities totaled $339.6 million during the nine months ended September 30, 2016, which primarily represents $477.0 million of borrowings under our bank credit facility less $135.5 million in repayments of borrowings under our bank credit facility. Net cash used in financing activities totaled $3.1 million during the nine months ended September 30, 2015, which primarily represents net payments for share-based compensation. During the nine months ended September 30, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility.
We had a working capital deficit at September 30, 2016 of $159.8 million, which included $292.4 million related to the 2017 Convertible Notes due on March 1, 2017.

37


Capital Expenditures.
During the three months ended September 30, 2016, additions to oil and gas property costs of $25.3 million included $0.5 million of lease and property acquisition costs, $4.8 million of capitalized SG&A expenses (inclusive of incentive compensation) and $6.9 million of capitalized interest. During the nine months ended September 30, 2016, additions to oil and gas property costs of $152.8 million included $1.7 million of lease and property acquisition costs, $17.1 million of capitalized SG&A expenses (inclusive of incentive compensation) and $21.2 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.
Contractual Obligations and Other Commitments
We have various contractual obligations and other commitments in the normal course of operations. For further information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Other Commitments” in our 2015 Annual Report on Form 10-K. On October 6, 2014, we entered into an agreement to contract the ENSCO 8503 deep water drilling rig for our multi-year deep water drilling program in the GOM. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. During the third quarter of 2016, we terminated an offshore vessel contract and an Appalachian drilling rig contract. Other than the terminations of the Ensco contract, offshore vessel contract and Appalachian rig contract, there have been no material changes to this disclosure during the nine months ended September 30, 2016.

38


Results of Operations
The following tables set forth certain information with respect to our oil and gas operations:
 
Three Months Ended
September 30,
 
 
 
 
 
2016
 
2015
 
Variance
 
% Change
Production:
 
 
 
 
 
 
 
Oil (MBbls)
1,563

 
1,509

 
54

 
4
 %
Natural gas (MMcf)
8,096

 
8,328

 
(232
)
 
(3
)%
NGLs (MBbls)
686

 
765

 
(79
)
 
(10
)%
Oil, natural gas and NGLs (MBoe)
3,598

 
3,662

 
(64
)
 
(2
)%
Oil, natural gas and NGLs (MMcfe)
21,590

 
21,972

 
(382
)
 
(2
)%
Revenue data (in thousands): (1)
 
 
 
 
 
 
 
Oil revenue
$
71,116

 
$
105,013

 
$
(33,897
)
 
(32
)%
Natural gas revenue
15,601

 
17,367

 
(1,766
)
 
(10
)%
NGLs revenue
6,666

 
5,980

 
686

 
11
 %
Total oil, natural gas and NGL revenue
$
93,383

 
$
128,360

 
$
(34,977
)
 
(27
)%
Average prices:
 
 
 
 
 
 
 
Prior to the cash settlement of effective hedging contracts
 
 
 
 
 
 
 
Oil (per Bbl)
$
42.10

 
$
45.51

 
$
(3.41
)
 
(7
)%
Natural gas (per Mcf)
1.63

 
1.65

 
(0.02
)
 
(1
)%
NGLs (per Bbl)
9.72

 
7.82

 
1.90

 
24
 %
Oil, natural gas and NGLs (per Boe)
23.82

 
24.15

 
(0.33
)
 
(1
)%
Oil, natural gas and NGLs (per Mcfe)
3.97

 
4.02

 
(0.05
)
 
(1
)%
Including the cash settlement of effective hedging contracts
 
 
 
 
 
 
 
Oil (per Bbl)
$
45.50

 
$
69.59

 
$
(24.09
)
 
(35
)%
Natural gas (per Mcf)
1.93

 
2.09

 
(0.16
)
 
(8
)%
NGLs (per Bbl)
9.72

 
7.82

 
1.90

 
24
 %
Oil, natural gas and NGLs (per Boe)
25.95

 
35.05

 
(9.10
)
 
(26
)%
Oil, natural gas and NGLs (per Mcfe)
4.33

 
5.84

 
(1.51
)
 
(26
)%
Expenses (per Mcfe):
 
 
 
 
 
 
 
Lease operating expenses
$
0.79

 
$
1.10

 
$
(0.31
)
 
(28
)%
Transportation, processing and gathering expenses
0.49

 
0.83

 
(0.34
)
 
(41
)%
SG&A expenses (2)
0.71

 
0.89

 
(0.18
)
 
(20
)%
DD&A expense on oil and gas properties
2.68

 
2.77

 
(0.09
)
 
(3
)%
 
(1)
Includes the cash settlement of effective hedging contracts.
(2)
Excludes incentive compensation expense.    


39


 
Nine Months Ended
September 30,
 
 
 
 
 
2016
 
2015
 
Variance
 
% Change
Production:
 
 
 
 
 
 
 
Oil (MBbls)
4,746

 
4,665

 
81

 
2
 %
Natural gas (MMcf)
20,042

 
32,066

 
(12,024
)
 
(37
)%
NGLs (MBbls)
1,294

 
2,242

 
(948
)
 
(42
)%
Oil, natural gas and NGLs (MBoe)
9,380

 
12,251

 
(2,871
)
 
(23
)%
Oil, natural gas and NGLs (MMcfe)
56,282

 
73,508

 
(17,226
)
 
(23
)%
Revenue data (in thousands): (1)
 
 
 
 
 
 
 
Oil revenue
$
204,102

 
$
324,105

 
$
(120,003
)
 
(37
)%
Natural gas revenue
43,327

 
72,611

 
(29,284
)
 
(40
)%
NGLs revenue
15,119

 
29,379

 
(14,260
)
 
(49
)%
Total oil, natural gas and NGL revenue
$
262,548

 
$
426,095

 
$
(163,547
)
 
(38
)%
Average prices:
 
 
 
 
 
 
 
Prior to the cash settlement of effective hedging contracts
 
 
 
 
 
 
 
Oil (per Bbl)
$
38.86

 
$
48.74

 
$
(9.88
)
 
(20
)%
Natural gas (per Mcf)
1.68

 
1.94

 
(0.26
)
 
(13
)%
NGLs (per Bbl)
11.68

 
13.10

 
(1.42
)
 
(11
)%
Oil, natural gas and NGLs (per Boe)
24.86

 
26.04

 
(1.18
)
 
(5
)%
Oil, natural gas and NGLs (per Mcfe)
4.14

 
4.34

 
(0.20
)
 
(5
)%
Including the cash settlement of effective hedging contracts
 
 
 
 
 
 
 
Oil (per Bbl)
$
43.01

 
$
69.48

 
$
(26.47
)
 
(38
)%
Natural gas (per Mcf)
2.16

 
2.26

 
(0.10
)
 
(4
)%
NGLs (per Bbl)
11.68

 
13.10

 
(1.42
)
 
(11
)%
Oil, natural gas and NGLs (per Boe)
27.99

 
34.78

 
(6.79
)
 
(20
)%
Oil, natural gas and NGLs (per Mcfe)
4.66

 
5.80

 
(1.14
)
 
(20
)%
Expenses (per Mcfe):
 
 
 
 
 
 
 
Lease operating expenses
$
0.98

 
$
1.08

 
$
(0.10
)
 
(9
)%
Transportation, processing and gathering expenses
0.33

 
0.76

 
(0.43
)
 
(57
)%
SG&A expenses (2)
0.86

 
0.72

 
0.14

 
19
 %
DD&A expense on oil and gas properties
2.90

 
3.03

 
(0.13
)
 
(4
)%
(1)
Includes the cash settlement of effective hedging contracts.
(2)
Excludes incentive compensation expense.    

Net Loss. During the three months ended September 30, 2016, we reported a net loss totaling approximately $89.6 million, or $16.01 per share, compared to a net loss for the three months ended September 30, 2015 of $292.0 million, or $52.82 per share. During the nine months ended September 30, 2016, we reported a net loss totaling approximately $474.2 million, or $84.90 per share, compared to a net loss for the nine months ended September 30, 2015 of $772.3 million, or $139.83 per share. All per share amounts are on a diluted basis.
We follow the full cost method of accounting for oil and gas properties. During the three months ended September 30, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $36.5 million and $295.7 million, respectively. During the nine months ended September 30, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $284.0 million and $1,011.4 million, respectively. During the three months ended March 31, 2016, we recognized a ceiling test write-down of our Canadian oil and gas properties, which were deemed fully impaired at the end of 2015, totaling $0.3 million. The write-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.
The variance in the three and nine month periods’ results was also due to the following components:
Production. During the three months ended September 30, 2016, total production volumes decreased to 21.6 Bcfe compared to 22.0 Bcfe produced during the comparable 2015 period, representing a 2% decrease. Oil production during the three months ended September 30, 2016 totaled approximately 1,563 MBbls compared to 1,509 MBbls produced during the comparable 2015 period. Natural gas production totaled 8.1 Bcf during the three months ended September 30, 2016 compared to 8.3 Bcf during the comparable 2015 period. NGL production during the three months ended September 30, 2016 totaled approximately 686 MBbls compared to 765 MBbls produced during the comparable 2015 period.

40


During the nine months ended September 30, 2016, total production volumes decreased to 56.3 Bcfe compared to 73.5 Bcfe produced during the comparable 2015 period, representing a 23% decrease. Oil production during the nine months ended September 30, 2016 totaled approximately 4,746 MBbls compared to 4,665 MBbls produced during the comparable 2015 period. Natural gas production totaled 20.0 Bcf during the nine months ended September 30, 2016 compared to 32.1 Bcf during the comparable 2015 period. NGL production during the nine months ended September 30, 2016 totaled approximately 1,294 MBbls compared to 2,242 MBbls produced during the comparable 2015 period. The decreases in natural gas and NGL production volumes during the nine months ended September 30, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.
On October 20, 2016, we entered into the PSA for the sale of our Appalachia properties, with an expected closing date of February 27, 2017 (see "Overview – Restructuring Support Agreement and Purchase and Sale Agreement"). For the three months ended September 30, 2016, total production volumes attributable to our Appalachia properties were approximately 10.3 Bcfe, comprised of 5.7 Bcf of natural gas, 124 MBbls of oil and 645 MBbls of NGLs. For the nine months ended September 30, 2016, total production volumes attributable to our Appalachia properties were approximately 15.9 Bcfe, comprised of 9.6 Bcf of natural gas, 155 MBbls of oil and 897 MBbls of NGLs.
Prices. Prices realized during the three months ended September 30, 2016 averaged $45.50 per Bbl of oil, $1.93 per Mcf of natural gas and $9.72 per Bbl of NGLs, compared to average realized prices of $69.59 per Bbl of oil, $2.09 per Mcf of natural gas and $7.82 per Bbl of NGLs during the comparable 2015 period. Prices realized during the nine months ended September 30, 2016 averaged $43.01 per Bbl of oil, $2.16 per Mcf of natural gas and $11.68 per Bbl of NGLs, or 20% lower, on an Mcfe basis, than average realized prices of $69.48 per Bbl of oil, $2.26 per Mcf of natural gas and $13.10 per Bbl of NGLs during the comparable 2015 period. All unit pricing amounts include the cash settlement of effective hedging contracts.
We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. Our effective hedging transactions increased our average realized natural gas price by $0.30 per Mcf and increased our average realized oil price by $3.40 per Bbl during the three months ended September 30, 2016. During the three months ended September 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.44 per Mcf and increased our average realized oil price by $24.08 per Bbl. During the nine months ended September 30, 2016, our effective hedging transactions increased our average realized natural gas price by $0.48 per Mcf and increased our average realized oil price by $4.15 per Bbl. During the nine months ended September 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.32 per Mcf and increased our average realized oil price by $20.74 per Bbl.
Revenue. Oil, natural gas and NGL revenue was $93.4 million during the three months ended September 30, 2016 compared to $128.4 million during the comparable period of 2015. For the nine months ended September 30, 2016 and 2015, oil, natural gas and NGL revenue totaled $262.5 million and $426.1 million, respectively. The decrease in total revenue for the three months ended September 30, 2016 was primarily due to a 2% decrease in production volumes and a 35% decrease in average realized oil prices from the comparable period of 2015. The decrease in total revenue for the nine months ended September 30, 2016 was primarily due to a 23% decrease in production volumes and a 20% decrease in average realized prices on an equivalent basis from the comparable period of 2015. For the three and nine months ended September 30, 2016, total oil, natural gas and NGL revenues attributable to our Appalachia properties were $16.5 million and $27.7 million, respectively.
Derivative Income/Expense. Net derivative expense for the three months ended September 30, 2016 totaled $0.2 million, comprised of $0.2 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments and an immaterial cash settlement. For the three months ended September 30, 2015, net derivative expense totaled $2.4 million, comprised of $5.3 million of income from cash settlements and $2.9 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. Net derivative expense for the nine months ended September 30, 2016 totaled $0.7 million, comprised of $0.6 million of income from cash settlements and $1.3 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the nine months ended September 30, 2015, net derivative income totaled $4.9 million, comprised of $15.7 million of income from cash settlements and $10.8 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.
Expenses. Lease operating expenses during the three months ended September 30, 2016 and 2015 totaled $17.0 million and $24.2 million, respectively. For the nine months ended September 30, 2016 and 2015, lease operating expenses totaled $55.3 million and $79.3 million, respectively. On a unit of production basis, lease operating expenses were $0.79 per Mcfe and $1.10 per Mcfe for the three months ended September 30, 2016 and 2015, respectively, and $0.98 per Mcfe and $1.08 per Mcfe for the nine months ended September 30, 2016 and 2015, respectively. The decrease in lease operating expenses during the three and nine months ended September 30, 2016 was primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. For the three and nine months ended September 30, 2016, lease operating expenses attributable to our Appalachia properties were $2.9 million and $9.0 million, respectively.
TP&G expenses during the three months ended September 30, 2016 and 2015 totaled $10.6 million and $18.2 million, respectively, or $0.49 per Mcfe and $0.83 per Mcfe, respectively. For the nine months ended September 30, 2016 and 2015, TP&G expenses totaled $18.7 million and $55.9 million, respectively, or $0.33 per Mcfe and $0.76 per Mcfe, respectively. The decrease in TP&G expenses

41


during the three months ended September 30, 2016 was due primarily to the beneficial terms of the interim gas gathering and processing agreement in Appalachia that was executed at the end of the second quarter of 2016. The decrease in TP&G expenses during the nine months ended September 30, 2016 was primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016, as well as the recoupment of previously paid transportation costs allocable to the Federal government's portion of certain of our deep water production, which amounted to approximately $4 million. For the three and nine months ended September 30, 2016, TP&G expenses attributable to our Appalachia properties were $9.6 million and $17.2 million, respectively.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three months ended September 30, 2016 totaled $57.8 million compared to $60.8 million during the comparable period of 2015. For the nine months ended September 30, 2016 and 2015, DD&A expense totaled $163.4 million and $222.8 million, respectively. On a unit of production basis, DD&A expense was $2.68 per Mcfe and $2.77 per Mcfe during the three months ended September 30, 2016 and 2015, respectively. For the nine months ended September 30, 2016 and 2015, DD&A expense, on a unit of production basis, was $2.90 per Mcfe and $3.03 per Mcfe, respectively. The decrease in DD&A during the three and nine months ended September 30, 2016 was primarily due to the ceiling test write-downs of our oil and gas properties.
Other operational expenses for the three months ended September 30, 2016 and 2015 totaled $9.1 million and $0.4 million, respectively. Included in other operational expenses for the three months ended September 30, 2016 are $7.5 million in charges related to the terminations of an offshore vessel contract and an Appalachian drilling rig contract and approximately $1.7 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Appalachian drilling rig and the platform rig at Pompano. For the nine months ended September 30, 2016 and 2015, other operational expenses totaled $49.3 million and $1.6 million, respectively. Included in other operational expenses for the nine months ended September 30, 2016 are the $7.5 million in charges for the offshore vessel and Appalachian drilling rig contract terminations, a $20 million charge related to the termination of our deep water drilling rig contract with Ensco in June 2016, approximately $15.3 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Appalachian drilling rig and the platform rig at Pompano, and a $6.0 million cumulative foreign currency translation loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, which was reclassified from accumulated other comprehensive income.
SG&A expenses (exclusive of incentive compensation) for the three months ended September 30, 2016 were $15.4 million compared to $19.6 million for the three months ended September 30, 2015. For the nine months ended September 30, 2016 and 2015, SG&A expenses (exclusive of incentive compensation) totaled $48.2 million and $53.0 million, respectively. On a unit of production basis, SG&A expenses were $0.71 per Mcfe and $0.89 per Mcfe for the three months ended September 30, 2016 and 2015, respectively. For the nine months ended September 30, 2016 and 2015, SG&A expenses, on a unit of production basis, were $0.86 per Mcfe and $0.72 per Mcfe, respectively. The decrease in SG&A expenses for the three and nine months ended September 30, 2016 was primarily attributable to staff and other cost reductions. SG&A expenses for the three months ended September 30, 2015 included $2.1 million of lease termination charges associated with the early termination of an office lease.
For the three and nine months ended September 30, 2016, restructuring fees totaled $5.8 million and $16.2 million, respectively. These fees related to expenses supporting a restructuring effort including legal and financial advisory costs for Stone, our bank group and our noteholders.
For the three months ended September 30, 2016 and 2015, incentive compensation expense totaled $2.2 million and $0.8 million, respectively. For the nine months ended September 30, 2016 and 2015, incentive compensation expense totaled $11.8 million and $3.6 million, respectively. The 2016 incentive compensation cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Portions of the 2016 incentive cash bonuses replace amounts previously awarded to employees as stock-based compensation, reflected in SG&A expenses, resulting in higher incentive compensation expense in the 2016 periods as compared to the 2015 periods. 
Interest expense for the three months ended September 30, 2016 totaled $16.9 million, net of $6.9 million of capitalized interest, compared to interest expense of $10.9 million, net of $10.3 million of capitalized interest, during the comparable 2015 period. For the nine months ended September 30, 2016, interest expense totaled $49.8 million, net of $21.2 million of capitalized interest, compared to interest expense of $31.7 million, net of $31.9 million of capitalized interest, during the comparable 2015 period. The increase in interest expense was primarily the result of interest expense associated with the increased borrowings under our bank credit facility and a decrease in the amount of interest capitalized to oil and gas properties.
For the nine months ended September 30, 2016 and 2015, we recorded an income tax provision (benefit) of $6.8 million and ($280.8) million, respectively. The income tax benefit recorded for the nine months ended September 30, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. The change in the valuation allowance was recorded as an adjustment to income tax expense.

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Off-Balance Sheet Arrangements
None.
Recent Accounting Developments
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. The standard 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.
In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230) , Classification of Certain Cash Receipts and Cash Payments" to reduce diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2017, and 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 2016-15 in the same period, and any adjustments should be reflected as of the beginning of the fiscal year that includes that interim 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.
Defined Terms
Oil, condensate and NGLs are stated in barrels (“Bbls”) or thousand barrels (“MBbls”). Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil, condensate and NGLs are converted to natural gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. MMBoe and MBoe represent one million and one thousand barrels of oil equivalent, respectively. MMBtu represents one million British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property. Liquidity is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the nine months ended September 30, 2016, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $17.8 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $23.3 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.
Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given year without the consent of the board of directors. We believe that our hedging positions as of November 7, 2016 have hedged approximately 25% of our estimated 2016 production from estimated proved reserves. Although we continue to monitor the marketplace for additional hedges for 2016 and beyond, continued weakness in commodity prices may impair our ability to secure hedges at prices we deem acceptable. See Part I, Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.
Since the filing of our 2015 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

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Interest Rate Risk
We had total debt outstanding of $1,428 million at September 30, 2016, of which $1,086 million, or 76%, bears interest at fixed rates. The $1,086 million of fixed-rate debt is comprised of $300 million of the 2017 Convertible Notes, $775 million of the 2022 Notes and $11 million of the Building Loan. At September 30, 2016, the remaining $342 million of our outstanding debt bears interest at an adjustable interest rate and consists of borrowings outstanding under our bank credit facility. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of this Form 10-Q. Borrowings under our bank credit facility may subject us to increased sensitivity to interest rate movements. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. At September 30, 2016, the weighted average interest rate under our bank credit facility was approximately 3.1% per annum.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2016 at the reasonable assurance level.
Changes in Internal Controls Over Financial Reporting
There has not been any change in our internal control over financial reporting that occurred during the quarter ended September 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION
 
Item 1. Legal Proceedings
We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.
On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. A Coastal Zone Management ("CZM") test case in Jefferson Parish was recently dismissed for failure to exhaust administrative remedies, a conclusion that is being challenged by the Louisiana Department of Natural Resources ("LDNR").
In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 CZM suits filed by the Plaquemines Parish. On April 7, 2016, the LDNR filed a Petition for Intervention in this lawsuit.
On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern, with the participation of the PADEP and Stone, is now complete. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.
Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters.
Item 1A. Risk Factors
The following updates the Risk Factors included in our 2015 Annual Report on Form 10-K. Except as set forth below, there have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our 2015 Annual Report on Form 10-K.
Risks Relating to the Restructuring Support Agreement
The Restructuring Support Agreement (the “RSA”) is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the RSA is terminated, our ability to confirm and consummate the pre-packaged plan of reorganization (the"Plan") could be materially and adversely affected.
The RSA contains certain covenants on the part of the Company and certain (i) holders of the Company’s 1 ¾% Senior Convertible Notes due 2017 (the “Convertible Notes”) and (ii) holders of the Company’s 7 ½% Senior Notes due 2022 (together with the Convertible Notes, the “Notes” and the holders thereof, the “Noteholders”) who are signatories to the RSA, including that the Noteholders will vote in favor of the Plan, support the sale by us of our approximately 86,000 net acres in the Appalachia regions of Pennsylvania and West Virginia (the “Properties”) and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the RSA. The RSA sets forth certain conditions we must satisfy, including the timely satisfaction of certain milestones in the chapter 11 proceeding set forth in Schedule 1 to the RSA, as amended by the RSA Amendment, such as confirmation of the Plan and effectiveness of the Plan. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by us of the Properties for a cash purchase price of at least $350 million and approval of a United States Bankruptcy Court (the “Bankruptcy Court”). Our ability to timely complete such milestones is subject to risks and uncertainties that may be beyond our control.
The RSA also provides for termination by each party, or by either party, upon the occurrence of certain events, including without limitation, termination by the Required Consenting Noteholders (as defined in the RSA) upon the failure of the Company to achieve

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certain milestones set forth in Schedule 1 to the RSA, as amended by the RSA Amendment. For example, the Noteholders will have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases exceeds an amount acceptable to the Noteholders. If the RSA is terminated, each of the parties thereto will be released from their obligations in accordance with the terms of the RSA. Such termination may result in the loss of support for the Plan by the parties to the RSA, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that any new plan of reorganization would be as favorable to holders of claims as the current Plan and our chapter 11 proceedings could become protracted, which could significantly and detrimentally impact our relationships with vendors, suppliers, employees and customers.
Although we intend to pursue the restructuring in accordance with the terms set forth in the RSA and the RSA Amendment, there can be no assurance that we will be successful in completing a restructuring or any other similar transaction on the terms set forth in the RSA and the RSA Amendment, on different terms or at all.
We will be subject to the risks and uncertainties associated with chapter 11 proceedings.
The RSA contemplates that the Company will file for voluntary relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court on or before December 9, 2016 to implement the Plan in accordance with the term sheet annexed to the RSA. As a consequence of our filing for relief under chapter 11 of the Bankruptcy Code, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, will be subject to the risks and uncertainties associated with bankruptcy. These risks include the following:
•
our ability to prosecute, confirm and consummate the Plan or another plan of reorganization with respect to the chapter 11 proceedings;
•
the high costs of bankruptcy proceedings and related fees;
•
our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
•
our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;
•
our ability to maintain contracts that are critical to our operations;
•
our ability to execute our business plan in the current depressed commodity price environment;
•
the ability to attract, motivate and retain key employees;
•
the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
•
the ability of third parties to seek and obtain court approval to convert the chapter 11 proceedings to chapter 7 proceedings; and
•
the actions and decisions of our creditors and other third parties who have interests in our chapter 11 proceedings that may be inconsistent with our plans.

Delays in our chapter 11 proceedings increase the risks of our inability to reorganize our business and emerge from bankruptcy and may increase our costs associated with the bankruptcy process.
These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that occur during our chapter 11 proceedings that may be inconsistent with our plans.
We may not be able to obtain confirmation of the Plan as outlined in the RSA.
There can be no assurance that the Plan as outlined in the RSA (or any other plan of reorganization) will be approved by the Bankruptcy Court, so we urge caution with respect to existing and future investments in our securities.
The success of any reorganization will depend on approval by the Bankruptcy Court and the willingness of existing debt and security holders to agree to the exchange or modification of their interests as outlined in the Plan, and there can be no guarantee of success with respect to the Plan or any other plan of reorganization. We might receive official objections to confirmation of the Plan from the various bankruptcy committees and stakeholders in the chapter 11 proceedings. We cannot predict the impact that any objection might have on the Plan or on a Bankruptcy Court's decision to confirm the Plan. Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.
If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us, including holders of our secured and unsecured debt and equity, would ultimately receive with respect to their claims. Once commenced, there can be no assurance as to whether we will successfully reorganize and emerge from chapter 11 or, if we do successfully reorganize, as to when we would emerge from chapter 11. If no plan of reorganization can be confirmed,

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or if the Bankruptcy Court otherwise finds that it would be in the best interest of holders of claims and interests, the chapter 11 cases may be converted to cases under chapter 7 of the Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code.
Upon emergence from bankruptcy, our historical financial information may not be indicative of our future financial performance.
Our capital structure will be significantly altered under the Plan. Under fresh-start reporting rules that may apply to us upon the effective date of the Plan (or any alternative plan of reorganization), our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.
The pursuit of the RSA has consumed, and the chapter 11 proceedings will continue to consume, a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.
Although the Plan is designed to minimize the length of our chapter 11 proceedings, it is impossible to predict with certainty the amount of time that we may spend in bankruptcy or to assure parties in interest that the Plan will be confirmed. The chapter 11 proceedings will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the chapter 11 proceedings are protracted.
During the pendency of the chapter 11 proceedings, our employees will face considerable distraction and uncertainty, and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.
Trading in our securities is highly speculative and poses substantial risks. Under the Plan, following effectiveness of the Plan, the holders of our existing common stock will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants, which interests could be further diluted by the warrants and the management incentive plan contemplated by the Plan.
The Plan, as contemplated in the RSA, provides that upon the Company's emergence from chapter 11, Noteholders will receive their pro rata share of (a) $150 million of the net cash proceeds from the sale of the Properties plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any, (b) 95% of the common stock in the reorganized Company and (c) $225 million of new 7.5% second lien notes due 2022 and that the holders of the existing common stock of the Company will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. If the Plan as contemplated in the RSA is confirmed, up to 10% of the equity interests in the reorganized Company will be reserved for issuance as awards under a post-restructuring management incentive plan. Issuances of common stock (or securities convertible into or exercisable for common stock) under the management incentive plan and any exercises of the warrants for shares of common stock will dilute the voting power of the outstanding common stock and may adversely affect the trading price of such common stock.
Upon our emergence from bankruptcy, the composition of our board of directors may change significantly.
Under the Plan, the composition of our board of directors may change significantly. Upon emergence, the board will be made up of seven directors selected by the Required Consenting Noteholders, one of which will be our Chief Executive Officer. The Required Consenting Noteholders have agreed to interview any of the existing members of our board who wishes to continue as a member of our board. However, it is possible that up to six of our seven board members may be new to the Company. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
Assuming the Plan were effective as of the date hereof, it is estimated that twelve bondholders who currently hold approximately 85% of the Notes would own over 80% of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares

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or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.
We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.
Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout the chapter 11 proceedings. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the chapter 11 proceedings, allow us to proceed with the confirmation of a chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs.
Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate the Plan or any other chapter 11 plan of reorganization, and (v) the cost, duration and outcome of the chapter 11 proceedings.
The Plan and any other plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our Plan may be unsuccessful in its execution.
The Plan and any other plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.
In addition, the Plan and any other plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.
We may be subject to claims that will not be discharged in our chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.
The Bankruptcy Code provides that the confirmation of a chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.
Even if a chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.
Even if the Plan or any other chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our

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oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other chapter 11 plan of reorganization will achieve our stated goals.
Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.
Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if the Plan is confirmed.
For the duration of the chapter 11 proceedings, we may not be able to enter into commodity derivatives covering estimated future production on favorable terms or at all.
During the chapter 11 proceedings, our ability to enter into new commodity derivatives covering estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges. As a result, we may not be able to enter into additional commodity derivatives covering production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.
Transfers or issuances of our equity before or in connection with our chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We had net operating loss carryforwards of approximately $336 million as of December 31, 2015. We believe that our consolidated group will generate additional net operating losses for the 2016 tax year. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce our U.S. federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change”, as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change”, the amount of its net operating losses that may be utilized to offset future table income generally is subject to an annual limitation. Even if the net operating loss carryforwards are subject to limitation under Section 382, the net operating losses can be further reduced by the amount of discharge of indebtedness arising in a chapter 11 case under Section 108 of the Internal Revenue Code.
We expect to request that the Bankruptcy Court approve restrictions on certain transfers of our stock to limit the risk of an "ownership change" prior to our restructuring in our chapter 11 proceedings. Following the implementation of a plan of reorganization, it is likely that an “ownership change” will be deemed to occur and our net operating losses will nonetheless be subject to annual limitation.

Risks Relating to the Purchase and Sale Agreement
The Purchase and Sale Agreement (the “PSA”) providing for the sale by us of the Properties to Tug Hill (the “Disposition”) is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the PSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.
The PSA contains customary representations, warranties and covenants. The parties expect to close the Disposition by February 27, 2017, subject to customary closing conditions and approval by the Bankruptcy Court. The PSA may be terminated, subject to certain exceptions, (1) upon mutual written consent, (2) if the closing has not occurred by March 1, 2017, (3) for certain material breaches of representations and warranties or covenants that remain uncured, (4) if, on or prior to the end of the Diligence Period on December 19, 2016, title and environmental defect amounts (after application of customary thresholds and deductibles), casualty losses and the value of any assets excluded from the Properties due to the exercise of preferential purchase rights or consents equal or exceed $10 million in the aggregate, (5) if we fail to file for bankruptcy on or before December 9, 2016, (6) if the Bankruptcy Court does not enter an order approving our assumption of the PSA and certain other matters within 30 days of our filing for bankruptcy, (7) if the Bankruptcy Court does not enter a sale order for the Disposition by February 10, 2017, and (8) upon the occurrence of certain other events specified in the PSA. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by us of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. If the PSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

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Following the Disposition of the Properties, our production, revenue and cash flow from operating activities will be derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Following the Disposition of the Properties, our production, revenue and cash flow from operating activities will be derived from assets that are concentrated in a single geographic area in the GOM. Approximately 72% of our production during the first nine months of 2016 was associated with our GOM deep water, Gulf Coast deep gas and GOM conventional shelf properties. Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may:
•
subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and
•
result in our dependency upon a single or limited number of hydrocarbon basins.

In addition, the geographic concentration of our properties in the GOM and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:

•
severe weather, such as hurricanes and other adverse weather conditions;
•
delays or decreases in production, the availability of equipment, facilities or services;
•
delays or decreases in the availability of capacity to transport, gather or process production; and/or
•
changes in the regulatory environment such as the new guidelines recently issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the outer continental shelf.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the GOM during the initial few years when compared to other regions in the United States. Typically, 50% of the reserves of properties in the GOM are depleted within three to four years with natural gas wells having a higher rate of depletion than oil wells. Due to high initial production rates, production of reserves from reservoirs in the GOM generally decline more rapidly than from other producing reservoirs. As a result of the concentration of our operations in the GOM, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue.
In addition, we are particularly vulnerable to significant risk from hurricanes and tropical storms in the GOM. In past years, we have experienced shut-ins and losses of production due to the effects of hurricanes in the GOM. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses.
Because all or a number of our properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.
Other Risks
New guidelines recently issued by the federal Bureau of Ocean Energy Management ("BOEM") related to financial assurance requirements to cover decommissioning obligations for operations on the outer continental shelf may have a material adverse effect on our business, financial condition, or results of operations.
On July 14, 2016, BOEM issued a Notice to Lessees and Operators ("NTL") that augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency’s past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength.  Instead, BOEM will allow companies to “self-insure”, but only up to 10% of a company’s “tangible net worth”, which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. 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

50


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). BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans. 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 will be required, and we intend to work with BOEM to adjust our previously submitted tailored plan for the provision of new financial assurances required to be posted as a result of the new NTL. Our revised proposed plan would require approximately $35 million to $40 million of incremental financial assurance or bonding for 2016 through 2017, a portion of which may require cash collateral. Under the revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.
The closing market price of our common stock has recently declined significantly. On April 29 and May 17, 2016, we were notified by the NYSE that our common stock was not in compliance with NYSE listing standards. If we are unable to cure the market capitalization deficiency, our common stock could be delisted from the NYSE or trading could be suspended.
Our common stock is currently listed on the NYSE. In order for our common stock to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per share during a consecutive 30 trading-day period. In addition to the minimum average closing price criteria, we are considered to be below compliance if our average market capitalization over a consecutive 30 day-trading period is less than $50 million and, at the same time, our stockholders’ equity is less than $50 million.
On April 29, 2016, we were notified by the NYSE that the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million.
On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock in order to increase the per share trading price of our common stock in order to regain compliance with the NYSE’s minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement. We remain non-compliant with the $50 million average market capitalization and stockholders’ equity requirements.
On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE. After our submission of the business plan, the NYSE had 45 calendar days to review the plan to determine whether we have made reasonable demonstration of our ability to come into conformity with the relevant standards within the 18-month period. The NYSE accepted the plan on August 4, 2016 and will continue to review the Company on a quarterly basis for compliance with the plan. Upon acceptance of the plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50 million, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting. If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances causing the variance, and determine whether such variance warrants commencement of suspension and delisting procedures. Upon a delisting from the NYSE, we would commence trading on the OTC Pink. On September 20, 2016, we submitted our quarterly update to the business plan for the second of quarter 2016 and the NYSE notified us that it accepted the quarterly update on September 22, 2016.
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 or announcement of intent to file without immediate suspension and delisting of our common stock.
In addition to potentially commencing suspension or delisting procedures in respect of our common stock if we fail to meet the material aspects of the plan or any of the quarterly milestones or if we file for bankruptcy and do not have positive cash flow or are not in sound financial health, our common stock could be delisted pursuant to Section 802.01 of the NYSE Listed Company Manual if the trading price of our common stock on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per share, and our common stock could also be delisted pursuant to Section 802.01 if our average market capitalization over a consecutive 30 day-trading period is less than $15 million. In these events, we would not have an opportunity to cure the market capitalization

51


deficiency, and our shares would be delisted immediately and suspended from trading on the NYSE. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing, and attract and retain personnel by means of equity compensation, would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price of our common stock.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the three months ended September 30, 2016: 
Period
Total Number
of Shares
Purchased (1)
 
Average Price
Paid per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs (2)
 
Approximate Dollar Value of Shares that MayYet be
Purchased Under the
Plans or Programs
July 1 - July 31, 2016
1,639

 
$
12.40

 
—

 
 
August 1 - August 31, 2016
5,730

 
10.23

 
—

 
 
September1 - September 30, 2016
—

 
—

 
—

 
 
 
7,369

 
$
10.74

 
—

 
$
92,928,632


(1)
Amount includes shares of our common stock withheld from employees and nonemployee directors upon the vesting of restricted stock in order to satisfy the required tax withholding obligations.
(2)
There were no repurchases of our common stock under our share repurchase program during the three months ended September 30, 2016.
 

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Item 6. Exhibits
 
3.1

 
Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No. 001-12074)).
3.2

 
Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-12074)).
10.1

 
Restructuring Support Agreement, dated October 20, 2016, by and among Stone Energy Corporation and its subsidiaries party thereto and the Undersigned Creditor Parties (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 21, 2016 (File No. 001-12074)).
10.2

 
Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and TH Exploration III, LLC as buyer, dated October 20, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 21, 2016 (File No. 001-12074)).
10.3

 
First Amendment to Restructuring Support Agreement, dated November 4, 2016, by and among the Stone Parties and the Consenting Noteholders (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 4, 2016 (File No. 001-12074)).
*10.4

 
Letter Agreement dated August 10, 2016 between Stone Energy Corporation and Richard L. Toothman, Jr.
*31.1

 
Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2

 
Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1

 
Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
*101.INS

 
XBRL Instance Document
*101.SCH

 
XBRL Taxonomy Extension Schema Document
*101.CAL

 
XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF

 
XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB

 
XBRL Taxonomy Extension Label Linkbase Document
*101.PRE

 
XBRL Taxonomy Extension Presentation Linkbase Document
______________________________________________
*
Filed or furnished herewith.
#
Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

53


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
STONE ENERGY CORPORATION
 
 
 
 
Date:
November 7, 2016
By:
/s/ Kenneth H. Beer
 
 
 
Kenneth H. Beer
 
 
 
Executive Vice President and Chief Financial Officer
 
 
 
(On behalf of the Registrant and as
 
 
 
Principal Financial Officer)

54


EXHIBIT INDEX
 
Exhibit
Number
 
Description
3.1

 
Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No. 001-12074)).
3.2

 
Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-12074)).
10.1

 
Restructuring Support Agreement, dated October 20, 2016, by and among Stone Energy Corporation and its subsidiaries party thereto and the Undersigned Creditor Parties (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 21, 2016 (File No. 001-12074)).
10.2

 
Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and TH Exploration III, LLC as buyer, dated October 20, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 21, 2016 (File No. 001-12074)).
10.3

 
First Amendment to Restructuring Support Agreement, dated November 4, 2016, by and among the Stone Parties and the Consenting Noteholders (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 4, 2016 (File No. 001-12074)).
*10.4

 
Letter Agreement dated August 10, 2016 between Stone Energy Corporation and Richard L. Toothman, Jr.
*31.1

 
Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2

 
Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1

 
Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
*101.INS

 
XBRL Instance Document
*101.SCH

 
XBRL Taxonomy Extension Schema Document
*101.CAL

 
XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF

 
XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB

 
XBRL Taxonomy Extension Label Linkbase Document
*101.PRE

 
XBRL Taxonomy Extension Presentation Linkbase Document
______________________________________________
*
Filed or furnished herewith.
#
Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.



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