Stone Energy (SGY) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	x	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  x

As of November 5, 2013, there were 49,993,835 shares of the registrant’s common stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of September 30, 2013 and December 31, 2012		1
	Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2013 and 2012		2
	Condensed Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012		3
	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2013 and 2012		4
	Notes to Condensed Consolidated Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 4.	Controls and Procedures		30
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		30
Item 1A.	Risk Factors		31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		32
Item 6.	Exhibits		33
	Signatures		34

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	September 30,			December 31,
	2013			2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	243,075		$	279,526
Accounts receivable		189,565			167,288
Fair value of hedging contracts		14,423			39,655
Current income tax receivable		10,893			10,027
Deferred taxes		26,350			15,514
Inventory		3,843			4,207
Other current assets		1,439			3,626
Total current assets		489,588			519,843
Oil and gas properties, full cost method of accounting:
Proved		7,589,153			7,244,466
Less: accumulated depreciation, depletion and amortization		(5,762,937	)		(5,510,166	)
Net proved oil and gas properties		1,826,216			1,734,300
Unevaluated		576,395			447,795
Other property and equipment, net		23,965			22,115
Fair value of hedging contracts		5,114			9,199
Other assets, net		49,148			43,179
Total assets	$	2,970,426		$	2,776,431
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	104,486		$	94,361
Undistributed oil and gas proceeds		42,913			23,414
Accrued interest		14,272			18,546
Fair value of hedging contracts		8,261			149
Asset retirement obligations		60,938			66,260
Other current liabilities		21,680			16,765
Total current liabilities		252,550			219,495
Long-term debt		923,745			914,126
Deferred taxes		387,033			310,830
Asset retirement obligations		407,712			422,042
Fair value of hedging contracts		360			1,530
Other long-term liabilities		26,463			36,275
Total liabilities		1,997,863			1,904,298
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 48,750,533 and 48,392,552 shares, respectively		488			484
Treasury stock (16,582 shares, at cost)		(860	)		(860	)
Additional paid-in capital		1,393,439			1,386,475
Accumulated deficit		(426,917	)		(542,799	)
Accumulated other comprehensive income		6,413			28,833
Total stockholders’ equity		972,563			872,133
Total liabilities and stockholders’ equity	$	2,970,426		$	2,776,431

The accompanying notes are an integral part of this statement.

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,
	2013			2012			2013			2012
Operating revenue:
Oil production	$	186,608		$	180,806		$	558,031		$	564,745
Gas production		52,728			34,003			137,382			91,006
Natural gas liquids production		16,476			11,910			36,854			35,228
Other operational income		873			678			2,659			2,520
Derivative income, net		—			—			—			3,119
Total operating revenue		256,685			227,397			734,926			696,618
Operating expenses:
Lease operating expenses		53,986			60,995			157,547			157,030
Transportation, processing and gathering expenses		13,081			6,762			27,374			15,911
Production taxes		5,224			1,842			11,404			7,578
Depreciation, depletion and amortization		92,853			89,274			255,497			260,982
Accretion expense		8,431			8,405			25,012			24,926
Salaries, general and administrative expenses		14,201			13,673			43,351			40,521
Incentive compensation expense		4,566			67			8,047			3,907
Other operational expenses		237			82			382			195
Derivative expense, net		1,684			1,812			1,537			—
Total operating expenses		194,263			182,912			530,151			511,050
Income from operations		62,422			44,485			204,775			185,568
Other (income) expenses:
Interest expense		7,922			7,692			26,452			21,107
Interest income		(1,311	)		(117	)		(1,543	)		(227	)
Other income		(782	)		(443	)		(2,190	)		(1,229	)
Total other expenses		5,829			7,132			22,719	��		19,651
Income before income taxes		56,593			37,353			182,056			165,917
Provision (benefit) for income taxes:
Current		(88	)		595			(10,827	)		1,164
Deferred		20,579			13,099			77,001			59,573
Total income taxes		20,491			13,694			66,174			60,737
Net income	$	36,102		$	23,659		$	115,882		$	105,180
Basic earnings per share	$	0.72		$	0.48		$	2.32		$	2.13
Diluted earnings per share	$	0.72		$	0.48		$	2.32		$	2.13
Average shares outstanding		48,732			48,342			48,680			48,300
Average shares outstanding assuming dilution		48,776			48,384			48,720			48,343

The accompanying notes are an integral part of this statement.

2

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income	$	36,102		$	23,659		$	115,882		$	105,180
Other comprehensive income (loss), net of tax effect:
Derivatives		(18,384	)		(33,166	)		(22,164	)		7,971
Foreign currency items		267			—			(256	)		—
Comprehensive income (loss)	$	17,985		($	9,507	)	$	93,462		$	113,151

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,
	2013			2012
Cash flows from operating activities:
Net income	$	115,882		$	105,180
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		255,497			260,982
Accretion expense		25,012			24,926
Deferred income tax provision		77,001			59,573
Settlement of asset retirement obligations		(61,178	)		(47,211	)
Non-cash stock compensation expense		7,583			6,800
Excess tax benefits		(156	)		(882	)
Non-cash derivative expense (income)		1,626			(584	)
Non-cash interest expense		12,384			9,068
Other non-cash expense		—			16
Change in current income taxes		(704	)		(3,240	)
Increase in accounts receivable		(22,277	)		(15,832	)
(Increase) decrease in other current assets		2,187			(2,456	)
Decrease in inventory		158			136
Increase in accounts payable		8,035			6,116
Increase (decrease) in other current liabilities		20,251			(24,301	)
Other		(1,791	)		(4,378	)
Net cash provided by operating activities		439,510			373,913
Cash flows from investing activities:
Investment in oil and gas properties		(472,304	)		(445,311	)
Proceeds from sale of oil and gas properties, net of expenses		6,300			403
Sale of fixed assets		—			134
Investment in fixed and other assets		(3,830	)		(3,998	)
Change in restricted funds		(2,394	)		—
Net cash used in investing activities		(472,228	)		(448,772	)
Cash flows from financing activities:
Proceeds from bank borrowings		—			25,000
Repayments of bank borrowings		—			(70,000	)
Proceeds from issuance of senior convertible notes		—			300,000
Deferred financing costs of senior convertible notes		—			(8,855	)
Proceeds from sold warrants		—			40,170
Payments for purchased call options		—			(70,830	)
Deferred financing costs		(11	)		—
Excess tax benefits		156			882
Net payments for share-based compensation		(3,733	)		(3,773	)
Net cash (used in) provided by financing activities		(3,588	)		212,594
Effect of exchange rate changes on cash		(145	)		—
Net change in cash and cash equivalents		(36,451	)		137,735
Cash and cash equivalents, beginning of period		279,526			38,451
Cash and cash equivalents, end of period	$	243,075		$	176,186

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”) and its subsidiaries as of September 30, 2013 and for the three and nine month periods ended September 30, 2013 and 2012 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, 2012 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, 2012 (our “2012 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 2012 Annual Report on Form 10-K. The results of operations for the three and nine month periods ended September 30, 2013 are not necessarily indicative of future financial results.

Note 2 – 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,
	2013			2012			2013			2012
	(In thousands, except per share amounts)
Income (numerator):
Basic:
Net income	$	36,102		$	23,659		$	115,882		$	105,180
Net income attributable to participating securities		(924	)		(564	)		(2,728	)		(2,283	)
Net income attributable to common stock—basic	$	35,178		$	23,095		$	113,154		$	102,897
Diluted:
Net income	$	36,102		$	23,659		$	115,882		$	105,180
Net income attributable to participating securities		(923	)		(563	)		(2,726	)		(2,281	)
Net income attributable to common stock—diluted	$	35,179		$	23,096		$	113,156		$	102,899
Weighted average shares (denominator):
Weighted average shares—basic		48,732			48,342			48,680			48,300
Dilutive effect of stock options		44			42			40			43
Weighted average shares—diluted		48,776			48,384			48,720			48,343
Basic earnings per share	$	0.72		$	0.48		$	2.32		$	2.13
Diluted earnings per share	$	0.72		$	0.48		$	2.32		$	2.13

Stock options that were considered antidilutive because the exercise price of the options exceeded the average price of our common stock for the applicable period totaled approximately 327,000 and 369,000 shares during the three and nine month periods ended September 30, 2013 and 2012, respectively.

During the three months ended September 30, 2013 and 2012, respectively, approximately 22,000 and 59,000 shares of our common stock were issued from authorized shares upon the vesting (lapse of forfeiture restrictions) of restricted stock by employees and nonemployee directors. During the nine months ended September 30, 2013 and 2012, respectively, approximately 358,000 and 314,000 shares of our common stock were issued from authorized shares upon the vesting (lapse of forfeiture restrictions) of restricted stock by employees and nonemployee directors.

Because it is management’s stated intention to redeem the principal amount of our 1 ³⁄₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) (seeNote 4 – Long-Term Debt) in cash, we have used the treasury method for determining potential dilution in the diluted earnings per share computation. Since the average price of our common stock was less than the effective conversion price for such notes during the reporting period, the 2017 Convertible Notes were not dilutive for such period. Additionally, since the average price of our common stock was less than the strike price of the Sold Warrants (as defined inNote 4 – Long-Term Debt) for the reporting period, such warrants were also not dilutive for such period.

5

Note 3 – 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 hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. These hedges are designated as cash flow hedges upon entering into the contract. We do not enter into hedging transactions for trading purposes. We have no fair value hedges.

The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, 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. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operations. Instruments not qualifying for hedge accounting treatment are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges are recognized in earnings through derivative expense (income) and cash flows from operations. Typically, a small portion of our derivative contracts are determined to be ineffective. This is 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.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2013, 2014 and 2015 oil and natural gas production from the Gulf Coast Basin. Some of our fixed-price oil swap 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, and some are based on the average of the Intercontinental Exchange closing price for Brent 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 to us if prices fall below the swap price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America, Natixis and Regions Bank.

All of our derivative instruments at September 30, 2013 and December 31, 2012 were designated as effective cash flow hedges. However, during the three and nine month periods ended September 30, 2013 and 2012, certain of our derivative contracts were determined to be partially ineffective. The following tables disclose the location and fair value amounts of derivative instruments reported in our balance sheet at September 30, 2013 and December 31, 2012.

Fair Value of Derivative Instruments at September 30, 2013
(In millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of hedging contracts	$	14.4	Current liabilities: Fair value of hedging contracts	($	8.3	)
	Long-term assets: Fair value of hedging contracts		5.1	Long-term liabilities: Fair value of hedging contracts		(0.3	)
		$	19.5		($	8.6	)
Fair Value of Derivative Instruments at December 31, 2012
(In millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of hedging contracts	$	39.7	Current liabilities: Fair value of hedging contracts	($	0.1	)
	Long-term assets: Fair value of hedging contracts		9.2	Long-term liabilities: Fair value of hedging contracts		(1.5	)
		$	48.9		($	1.6	)

6

The following tables disclose the effect of derivative instruments on the statement of operations for the three and nine month periods ended September 30, 2013 and 2012.

Effect of Derivative Instruments on the Statement of Operations for the Three Months Ended September 30, 2013 and 2012 (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)
	2013			2012			Location	2013			2012		Location	2013			2012
Commodity contracts	($	30.8	)	($	41.8	)	Operating revenue— oil/gas production	($	2.1	)	$	10.0	Derivative expense, net	($	1.7	)	($	1.8	)
Total	($	30.8	)	($	41.8	)		($	2.1	)	$	10.0		($	1.7	)	($	1.8	)

(a) For the three months ended September 30, 2013, effective hedging contracts decreased oil revenue by $7.5 million and increased gas revenue by $5.4 million. For the three months ended September 30, 2012, effective hedging contracts increased oil revenue by $4.1 million and increased gas revenue by $5.9 million.

Effect of Derivative Instruments on the Statement of Operations for the Nine Months Ended September 30, 2013 and 2012 (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)
	2013			2012		Location	2013		2012		Location	2013			2012
Commodity contracts	($	20.9	)	$	30.8	Operating revenue— oil/gas production	$	13.8	$	18.4	Derivative (expense) income, net	($	1.5	)	$	3.1
Total	($	20.9	)	$	30.8		$	13.8	$	18.4		($	1.5	)	$	3.1

(a) For the nine months ended September 30, 2013, effective hedging contracts increased oil revenue by $2.4 million and increased gas revenue by $11.4 million. For the nine months ended September 30, 2012, effective hedging contracts increased oil revenue by $1.1 million and increased gas revenue by $17.3 million.

At September 30, 2013, we had accumulated other comprehensive income of $6.6 million, net of tax, related to the fair value of our swap contracts that were outstanding as of September 30, 2013. We believe that approximately $3.8 million, net of tax, of the accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

Our derivative contracts are subject to netting arrangements. It is our policy not to offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following presents the potential impact of the rights of offset associated with our recognized assets and liabilities at September 30, 2013:

	As Presented Without Netting			Effects of Netting			With Effects of Netting
	(In millions)
Current assets: Fair value of hedging contracts	$	14.4		($	5.0	)	$	9.4
Long-term assets: Fair value of hedging contracts		5.1			(3.5	)		1.6
Current liabilities: Fair value of hedging contracts		(8.3	)		8.2			(0.1	)
Long-term liabilities: Fair value of hedging contracts		(0.3	)		0.3			—

7

The following table illustrates our hedging positions for calendar years 2013, 2014 and 2015 as of November 5, 2013:

	Fixed-Price Swaps NYMEX (except where noted)
	Natural Gas					Oil
	Daily Volume (MMBtus/d)			Swap Price ($)		Daily Volume (Bbls/d)			Swap Price ($)
2013		10,000			4.000		2,000	(a)		92.35
2013		10,000	(b)		4.050		1,000			92.80
2013		20,000	(a)		4.450		2,000	(c)		94.05
2013		10,000			5.270		1,000			94.45
2013		10,000			5.320		1,000			94.60
2013							1,000			97.15
2013							1,000			101.53
2013							1,000			103.00
2013							1,000			103.15
2013							1,000			104.25
2013							1,000			104.47
2013							1,000			104.50
2013							1,000	(d)		107.30
2014		10,000			4.000		1,000			90.06
2014		10,000			4.040		1,000			92.25
2014		10,000			4.105		1,000			93.55
2014		10,000			4.190		1,000			94.00
2014		10,000			4.250		1,000			98.00
2014		10,000			4.350		1,000			98.30
2014							2,000	(c)		98.85
2014							1,000			99.65
2014							1,000	(d)		103.30
2015		10,000			4.005		1,000			90.00
2015		10,000			4.220
2015		10,000			4.255

(a) July through December

(b) April through December

(c) January through June

(d) Brent crude oil contract

Note 4 – Long-Term Debt

Long-term debt consisted of the following at:

	September 30, 2013		December 31, 2012
	(In millions)
8 5⁄8% Senior Notes due 2017	$	375.0	$	375.0
1 3⁄4% Senior Convertible Notes due 2017		248.7		239.1
7 1⁄2% Senior Notes due 2022		300.0		300.0
Bank debt		—		—
Total long-term debt	$	923.7	$	914.1

Bank Debt

On April 26, 2011, we entered into an amended and restated revolving credit facility with commitments totaling $700 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On April 30, 2013, the bank group reaffirmed our existing borrowing base at $400 million. As of September 30 and November 5, 2013, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.5 million had been issued pursuant to the facility, leaving $378.5 million of availability under our bank credit facility.

8

During the three and nine month periods ended September 30, 2013, we recognized $0.5 million and $1.4 million, respectively, of interest expense related to fees on unused commitments under our bank credit facility. During the three and nine month periods ended September 30, 2013, we recognized $0.1 million and $0.4 million, respectively, of interest expense related to fees on our outstanding letters of credit.

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries 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. Our bank credit facility is guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”). Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At Stone’s option, loans under our bank credit facility will bear interest at a rate based on the adjusted London Interbank Offering (“Libor”) Rate plus an applicable margin, or a rate based on the prime rate or federal funds rate plus an applicable margin. Our bank credit facility provides for optional and mandatory prepayments, affirmative and negative covenants and interest coverage ratio and leverage ratio maintenance covenants. We were in compliance with all covenants as of September 30, 2013.

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, at our election, based on an initial conversion rate of 23.4449 shares of our common stock per $1,000 principal amount of 2017 Convertible Notes, which corresponds to an initial conversion price of approximately $42.65 per share of our common stock. On September 30, 2013, our closing share price was $32.43. 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, at our election. 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.

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 7,033,470 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes, 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(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91 per share of our common stock. 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.

As of September 30, 2013, the carrying amount of the liability component of the 2017 Convertible Notes was $248.7 million. During the three and nine month periods ended September 30, 2013, we recognized $3.3 million and $9.6 million, respectively, of interest expense for the amortization of the discount and $0.3 million and $0.9 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, 2013, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

2017 Notes

During the three and nine month periods ended September 30, 2013, we recognized $0.4 million and $1.2 million, respectively, of interest expense for the amortization of deferred financing costs related to the 8 ⁵⁄₈% Senior Notes due 2017 (the “2017 Notes”). During the three and nine month periods ended September 30, 2013, we recognized $8.1 million and $24.3 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Notes.

9

2022 Notes

During the three and nine month periods ended September 30, 2013, we recognized $0.2 million and $0.5 million, respectively, of interest expense for the amortization of deferred financing costs related to the 7 ¹⁄₂% Senior Notes due 2022 (the “2022 Notes”). During the three and nine month periods ended September 30, 2013, we recognized $5.6 million and $16.8 million, respectively, of interest expense related to the contractual interest coupon on the 2022 Notes.

Note 5 – Asset Retirement Obligations

The change in our asset retirement obligations during the nine months ended September 30, 2013 is set forth below:

	Nine Months Ended September 30, 2013
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	488.3
Liabilities incurred		16.5
Liabilities settled		(61.2	)
Accretion expense		25.0
Asset retirement obligations as of the end of the period, including current portion	$	468.6

Note 6 – Acquisitions

In December 2012, we closed on the acquisition of an office building. The acquisition was accounted for according to the guidance provided in Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires application of the acquisition method. This methodology requires us to record net assets acquired and consideration transferred at fair value. Differences between the net fair value of assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain. The building and land were recorded at fair value of $8.5 million. Consideration transferred in the transaction was $8.5 million in cash, with no goodwill or bargain purchase gain recorded.

On June 18, 2012, we completed the acquisition of a 25% working interest in the five block deep water Pompano field in Mississippi Canyon, an approximate 14% working interest in Mississippi Canyon Block 29 and a 10% working interest in certain aliquots of Mississippi Canyon Block 72. The acquisition was accounted for according to the guidance provided in ASC 805, Business Combinations. Consideration transferred in the transaction was $26.4 million in cash, with no goodwill or bargain purchase gain recorded. The following represents the allocation of the recorded value of net assets acquired in the transaction.

	(In millions)
Proved oil and gas properties	$	39.2
Unevaluated oil and gas properties		1.6
Asset retirement obligations		(14.4	)
Total fair value of net assets	$	26.4

Note 7 – 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, 2013 and December 31, 2012, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. 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. For a more detailed description of our derivative instruments, seeNote 3 – 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.

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at September 30, 2013:

	Fair Value Measurements at September 30, 2013
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	$	8.0		$	8.0	$	—		$	—
Hedging contracts		19.5			—		19.5			—
Total	$	27.5		$	8.0	$	19.5		$	—
	Fair Value Measurements at September 30, 2013
Liabilities	Total			Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(In millions)
Hedging contracts	($	8.6	)	$	—	($	8.6	)	$	—
Total	($	8.6	)	$	—	($	8.6	)	$	—

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012:

	Fair Value Measurements at December 31, 2012
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	$	13.5		$	13.5	$	—		$	—
Hedging contracts		48.9			—		48.9			—
Total	$	62.4		$	13.5	$	48.9		$	—
	Fair Value Measurements at December 31, 2012
Liabilities	Total			Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(In millions)
Hedging contracts	($	1.6	)	$	—	($	1.6	)	$	—
Total	($	1.6	)	$	—	($	1.6	)	$	—

The fair value of cash and cash equivalents and our variable-rate bank debt approximated book value at September 30, 2013 and December 31, 2012. As of September 30, 2013 and December 31, 2012, the fair value of the 2017 Notes was approximately $397.5 million and $401.3 million, respectively. As of September 30, 2013 and December 31, 2012, the fair value of the liability component of the 2017 Convertible Notes was approximately $287.4 million and $249.6 million, respectively. As of September 30, 2013 and December 31, 2012, the fair value of the 2022 Notes was approximately $317.3 million and $314.3 million, respectively.

The fair value of the 2017 Notes and the fair value of the 2022 Notes were determined based upon quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (seeNote 4 – Long-Term Debt) at inception, September 30, 2013 and December 31, 2012. 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.

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Note 8 – Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component for the three and nine month periods ended September 30, 2013 were as follows (in millions):

	Cash Flow Hedges			Foreign Currency Items			Total
For the Three Months Ended September 30, 2013
Beginning balance, net of tax	$	25.0		($	0.5	)	$	24.5
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(30.8	)		—			(30.8	)
Foreign currency translations		—			0.3			0.3
Income tax effect		11.1			—			11.1
Net of tax		(19.7	)		0.3			(19.4	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		2.1			—			2.1
Income tax effect		(0.8	)		—			(0.8	)
Net of tax		1.3			—			1.3
Other comprehensive income (loss), net of tax		(18.4	)		0.3			(18.1	)
Ending balance, net of tax	$	6.6		($	0.2	)	$	6.4
For the Nine Months Ended September 30, 2013
Beginning balance, net of tax	$	28.8		$	—		$	28.8
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(20.9	)		—			(20.9	)
Foreign currency translations		—			(0.2	)		(0.2	)
Income tax effect		7.6			—			7.6
Net of tax		(13.3	)		(0.2	)		(13.5	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(13.8	)		—			(13.8	)
Income tax effect		4.9			—			4.9
Net of tax		(8.9	)		—			(8.9	)
Other comprehensive income (loss), net of tax		(22.2	)		(0.2	)		(22.4	)
Ending balance, net of tax	$	6.6		($	0.2	)	$	6.4

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In 2012, 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 month periods ended September 30, 2012 were as follows (in millions):

	Cash Flow Hedges
For the Three Months Ended September 30, 2012
Beginning balance, net of tax	$	63.0
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(41.8	)
Income tax effect		15.0
Net of tax		(26.8	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(10.0	)
Income tax effect		3.6
Net of tax		(6.4	)
Other comprehensive income, net of tax		(33.2	)
Ending balance, net of tax	$	29.8
For the Nine Months Ended September 30, 2012
Beginning balance, net of tax	$	21.9
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		30.8
Income tax effect		(11.1	)
Net of tax		19.7
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(18.4	)
Income tax effect		6.6
Net of tax		(11.8	)
Other comprehensive income, net of tax		7.9
Ending balance, net of tax	$	29.8

Note 9 – Investment in Oil and Gas Properties

In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Included in unevaluated oil and gas property costs at September 30, 2013 are $9.7 million of capital expenditures related to our oil and gas property investments in Canada.

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Note 10 – Commitments and Contingencies

We are named as a defendant in certain lawsuits and are a party to certain 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.

Franchise Tax Action. We have been served with several petitions filed by the Louisiana Department of Revenue (the “LDR”) in Louisiana state court claiming additional franchise taxes due. In addition, we received preliminary assessments from the LDR for additional franchise taxes resulting from audits of Stone and other subsidiaries. These petitions and assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the Outer Continental Shelf (the “OCS”), which are transported through the State of Louisiana, should be sourced to the State of Louisiana for purposes of computing the Louisiana franchise tax apportionment ratio. We disagree with these contentions and are defending ourselves against these claims. Total asserted claims plus estimated accrued interest amount to approximately $30.5 million. The franchise tax years 2010, 2011 and 2012 for Stone remain subject to examination, which potentially exposes us to additional estimated assessments of $3.4 million including accrued interest. We estimate the potential range of loss upon resolution of this matter to be between $0 and $33.9 million.

Note 11 – Subsequent Event

In October 2013, we completed the sale of our interest in the Weeks Island field for cash consideration of approximately $46 million. The sale will be accounted for as an adjustment to capitalized costs with no gain or loss recognized.

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Note 12 – Guarantor Financial Statements

Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of the 2017 Convertible Notes, the 2017 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, 2013 and December 31, 2012 and for the three and nine month periods ended September 30, 2013 and 2012 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

SEPTEMBER 30, 2013

(In thousands)

	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	191,193		$	51,242		$	640		$	—		$	243,075
Accounts receivable		83,310			313,610			—			(207,355	)		189,565
Fair value of hedging contracts		—			14,423			—			—			14,423
Current income tax receivable		10,893			—			—			—			10,893
Deferred taxes *		6,631			19,719			—			—			26,350
Inventory		3,560			283			—			—			3,843
Other current assets		1,439			—			—			—			1,439
Total current assets		297,026			399,277			640			(207,355	)		489,588
Oil and gas properties, full cost method: Proved		1,211,964			6,377,189			—			—			7,589,153
Less: accumulated DD&A		(429,380	)		(5,333,557	)		—			—			(5,762,937	)
Net proved oil and gas properties		782,584			1,043,632			—			—			1,826,216
Unevaluated		274,986			291,750			9,659			—			576,395
Other property and equipment, net		23,965			—			—			—			23,965
Fair value of hedging contracts		—			5,114			—			—			5,114
Other assets, net		44,324			1,349			3,475			—			49,148
Investment in subsidiary		896,798			—			13,116			(909,914	)		—
Total assets	$	2,319,683		$	1,741,122		$	26,890		($	1,117,269	)	$	2,970,426
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	289,204		$	22,576		$	61		($	207,355	)	$	104,486
Undistributed oil and gas proceeds		39,141			3,772			—			—			42,913
Accrued interest		14,272			—			—			—			14,272
Fair value of hedging contracts		—			8,261			—			—			8,261
Asset retirement obligations		—			60,938			—			—			60,938
Other current liabilities		17,242			4,438			—			—			21,680
Total current liabilities		359,859			99,985			61			(207,355	)		252,550
Long-term debt		923,745			—			—			—			923,745
Deferred taxes *		31,295			355,738			—			—			387,033
Asset retirement obligations		5,758			401,954			—			—			407,712
Fair value of hedging contracts		—			360			—			—			360
Other long-term liabilities		26,463			—			—			—			26,463
Total liabilities		1,347,120			858,037			61			(207,355	)		1,997,863
Commitments and contingencies
Stockholders’ equity:
Common stock		488			—			—			—			488
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,393,439			1,496,509			27,404			(1,523,913	)		1,393,439
Accumulated deficit		(426,917	)		(620,093	)		(64	)		620,157			(426,917	)
Accumulated other comprehensive income (loss)		6,413			6,669			(511	)		(6,158	)		6,413
Total stockholders’ equity		972,563			883,085			26,829			(909,914	)		972,563
Total liabilities and stockholders’ equity	$	2,319,683		$	1,741,122		$	26,890		($	1,117,269	)	$	2,970,426

* Deferred income taxes have been allocated to the Guarantor Subsidiary where related oil and gas properties reside.

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CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2012

(In thousands)

	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	228,398		$	51,128		$	—	$	—		$	279,526
Accounts receivable		59,213			108,075			—		—			167,288
Fair value of hedging contracts		—			39,655			—		—			39,655
Current income tax receivable		10,027			—			—		—			10,027
Deferred taxes *		5,947			9,567			—		—			15,514
Inventory		3,924			283			—		—			4,207
Other current assets		3,626			—			—		—			3,626
Total current assets		311,135			208,708			—		—			519,843
Oil and gas properties, full cost method: Proved		1,004,808			6,239,658			—		—			7,244,466
Less: accumulated DD&A		(370,111	)		(5,140,055	)		—		—			(5,510,166	)
Net proved oil and gas properties		634,697			1,099,603			—		—			1,734,300
Unevaluated		254,757			193,038			—		—			447,795
Other property and equipment, net		22,115			—			—		—			22,115
Fair value of hedging contracts		—			9,199			—		—			9,199
Other assets, net		41,679			1,500			—		—			43,179
Investment in subsidiary		736,331			—			—		(736,331	)		—
Total assets	$	2,000,714		$	1,512,048		$	—	($	736,331	)	$	2,776,431
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	74,503		$	19,858		$	—	$	—		$	94,361
Undistributed oil and gas proceeds		21,841			1,573			—		—			23,414
Accrued interest		18,546			—			—		—			18,546
Fair value of hedging contracts		—			149			—		—			149
Asset retirement obligations		—			66,260			—		—			66,260
Other current liabilities		16,765			—			—		—			16,765
Total current liabilities		131,655			87,840			—		—			219,495
Long-term debt		914,126			—			—		—			914,126
Deferred taxes *		47,758			263,072			—		—			310,830
Asset retirement obligations		5,479			416,563			—		—			422,042
Fair value of hedging contracts		—			1,530			—		—			1,530
Other long-term liabilities		29,563			6,712			—		—			36,275
Total liabilities		1,128,581			775,717			—		—			1,904,298
Commitments and contingencies
Stockholders’ equity:
Common stock		484			—			—		—			484
Treasury stock		(860	)		—			—		—			(860	)
Additional paid-in capital		1,386,475			1,496,510			—		(1,496,510	)		1,386,475
Accumulated deficit		(542,799	)		(789,012	)		—		789,012			(542,799	)
Accumulated other comprehensive income		28,833			28,833			—		(28,833	)		28,833
Total stockholders’ equity		872,133			736,331			—		(736,331	)		872,133
Total liabilities and stockholders’ equity	$	2,000,714		$	1,512,048		$	—	($	736,331	)	$	2,776,431

* Deferred income taxes have been allocated to the Guarantor Subsidiary where related oil and gas properties reside.

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2013

(In thousands)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	6,904		$	179,704		$	—		$	—		$	186,608
Gas production		19,971			32,757			—			—			52,728
Natural gas liquids production		9,224			7,252			—			—			16,476
Other operational income		711			162			—			—			873
Total operating revenue		36,810			219,875			—			—			256,685
Operating expenses:
Lease operating expenses		3,895			50,091			—			—			53,986
Transportation, processing and gathering expenses		10,072			3,009			—			—			13,081
Production taxes		1,773			3,451			—			—			5,224
Depreciation, depletion, amortization		26,728			66,125			—			—			92,853
Accretion expense		93			8,338			—			—			8,431
Salaries, general and administrative		14,202			—			(1	)		—			14,201
Incentive compensation expense		4,566			—			—			—			4,566
Other operational expenses		194			43			—			—			237
Derivative expense, net		—			1,684			—			—			1,684
Total operating expenses		61,523			132,741			(1	)		—			194,263
Income (loss) from operations		(24,713	)		87,134			1			—			62,422
Other (income) expenses:
Interest expense		7,922			—			—			—			7,922
Interest income		(1,234	)		(69	)		(8	)		—			(1,311	)
Other income		(230	)		(552	)		—			—			(782	)
Income from investment in subsidiaries		(56,166	)		—			(7	)		56,173			—
Total other (income) expenses		(49,708	)		(621	)		(15	)		56,173			5,829
Income before taxes		24,995			87,755			16			(56,173	)		56,593
Provision (benefit) for income taxes:
Current		(88	)		—			—			—			(88	)
Deferred		(11,019	)		31,598			—			—			20,579
Total income taxes		(11,107	)		31,598			—			—			20,491
Net income	$	36,102		$	56,157		$	16		($	56,173	)	$	36,102
Comprehensive income	$	17,985		$	56,157		$	16		($	56,173	)	$	17,985

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2012

(In thousands)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	7,682		$	173,124		$	—		$	—		$	180,806
Gas production		9,197			24,806			—			—			34,003
Natural gas liquids production		5,436			6,474			—			—			11,910
Other operational income		568			(1	)		111			—			678
Total operating revenue		22,883			204,403			111			—			227,397
Operating expenses:
Lease operating expenses		5,886			55,107			2			—			60,995
Transportation, processing and gathering expenses		4,163			2,599			—			—			6,762
Production taxes		684			1,158			—			—			1,842
Depreciation, depletion, amortization		19,336			69,939			(1	)		—			89,274
Accretion expense		138			8,181			86			—			8,405
Salaries, general and administrative		13,672			1			—			—			13,673
Incentive compensation expense		67			—			—			—			67
Other operational expenses		61			21			—						82
Derivative expense, net		—			1,812			—			—			1,812
Total operating expenses		44,007			138,818			87			—			182,912
Income (loss) from operations		(21,124	)		65,585			24			—			44,485
Other (income) expenses:
Interest expense		7,671			21			—			—			7,692
Interest income		(112	)		(5	)		—			—			(117	)
Other income		(98	)		(345	)		—			—			(443	)
Income from investment in subsidiaries		(42,200	)		(24	)		—			42,224			—
Total other (income) expenses		(34,739	)		(353	)		—			42,224			7,132
Income before taxes		13,615			65,938			24			(42,224	)		37,353
Provision (benefit) for income taxes:
Current		595			—			—			—			595
Deferred		(10,639	)		23,738			—			—			13,099
Total income taxes		(10,044	)		23,738			—			—			13,694
Net income	$	23,659		$	42,200		$	24		($	42,224	)	$	23,659
Comprehensive income (loss)	($	9,507	)	$	42,200		$	24		($	42,224	)	($	9,507	)

18

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(In thousands)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	20,625		$	537,406		$	—		$	—		$	558,031
Gas production		47,240			90,142			—			—			137,382
Natural gas liquids production		17,901			18,953			—			—			36,854
Other operational income		2,150			509			—			—			2,659
Total operating revenue		87,916			647,010			—			—			734,926
Operating expenses:
Lease operating expenses		9,611			147,936			—			—			157,547
Transportation, processing and gathering expenses		17,853			9,521			—			—			27,374
Production taxes		3,960			7,444			—			—			11,404
Depreciation, depletion, amortization		62,007			193,490			—			—			255,497
Accretion expense		279			24,733			—			—			25,012
Salaries, general and administrative		43,300			4			47			—			43,351
Incentive compensation expense		8,047			—			—			—			8,047
Other operational expenses		295			87			—			—			382
Derivative expense, net		—			1,537			—			—			1,537
Total operating expenses		145,352			384,752			47			—			530,151
Income (loss) from operations		(57,436	)		262,258			(47	)		—			204,775
Other (income) expenses:
Interest expense		26,431			21			—			—			26,452
Interest income		(1,384	)		(144	)		(15	)		—			(1,543	)
Other income		(671	)		(1,519	)		—			—			(2,190	)
(Income) loss from investment in subsidiaries		(168,887	)		—			32			168,855			—
Total other (income) expenses		(144,511	)		(1,642	)		17			168,855			22,719
Income (loss) before taxes		87,075			263,900			(64	)		(168,855	)		182,056
Provision (benefit) for income taxes:
Current		(10,827	)		—			—			—			(10,827	)
Deferred		(17,980	)		94,981			—			—			77,001
Total income taxes		(28,807	)		94,981			—			—			66,174
Net income (loss)	$	115,882		$	168,919		($	64	)	($	168,855	)	$	115,882
Comprehensive income (loss)	$	93,462		$	168,919		($	64	)	($	168,855	)	$	93,462

19

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2012

(In thousands)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	20,729		$	544,016		$	—		$	—		$	564,745
Gas production		20,693			70,313			—			—			91,006
Natural gas liquids production		11,010			24,218			—			—			35,228
Other operational income		2,024			139			357			—			2,520
Derivative income, net		—			3,119			—			—			3,119
Total operating revenue		54,456			641,805			357			—			696,618
Operating expenses:
Lease operating expenses		17,108			139,937			(15	)		—			157,030
Transportation, processing and gathering expenses		8,361			7,550			—			—			15,911
Production taxes		2,354			5,224			—			—			7,578
Depreciation, depletion, amortization		45,884			214,908			190			—			260,982
Accretion expense		423			24,246			257			—			24,926
Salaries, general and administrative		40,516			5			—			—			40,521
Incentive compensation expense		3,907			—			—			—			3,907
Other operational expenses		150			45			—			—			195
Total operating expenses		118,703			391,915			432			—			511,050
Income (loss) from operations		(64,247	)		249,890			(75	)		—			185,568
Other (income) expenses:
Interest expense		21,189			(82	)		—			—			21,107
Interest income		(216	)		(11	)		—			—			(227	)
Other income		(121	)		(1,108	)		—			—			(1,229	)
(Income) loss from investment in subsidiaries		(160,650	)		75			—			160,575			—
Total other (income) expenses		(139,798	)		(1,126	)		—			160,575			19,651
Income (loss) before taxes		75,551			251,016			(75	)		(160,575	)		165,917
Provision (benefit) for income taxes:
Current		1,164			—			—			—			1,164
Deferred		(30,793	)		90,366			—			—			59,573
Total income taxes		(29,629	)		90,366			—			—			60,737
Net income (loss)	$	105,180		$	160,650		($	75	)	($	160,575	)	$	105,180
Comprehensive income (loss)	$	113,151		$	160,650		($	75	)	($	160,575	)	$	113,151

20

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(In thousands)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	115,882		$	168,919			($64)			($168,855)		$	115,882
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		62,007			193,490			—			—			255,497
Accretion expense		279			24,733			—			—			25,012
Deferred income tax provision (benefit)		(17,980	)		94,981			—			—			77,001
Settlement of asset retirement obligations		—			(61,178	)		—			—			(61,178	)
Non-cash stock compensation expense		7,583			—			—			—			7,583
Excess tax benefits		(156	)		—			—			—			(156	)
Non-cash derivative expense		—			1,626			—			—			1,626
Non-cash interest expense		12,384			—			—			—			12,384
Non-cash (income) loss from investment in subsidiaries		(168,887	)		—			32			168,855			—
Change in current income taxes		(704	)		—			—			—			(704	)
Change in intercompany receivables/payables		207,267			(207,311	)		44			—			—
(Increase) decrease in accounts receivable		(24,053	)		1,776			—			—			(22,277	)
Decrease in other current assets		2,187			—			—			—			2,187
Decrease in inventory		158			—			—			—			158
Increase in accounts payable		2,610			5,425			—			—			8,035
Increase in other current liabilities		13,613			6,638			—			—			20,251
Other		499			(2,290	)		—			—			(1,791	)
Net cash provided by operating activities		212,689			226,809			12			—			439,510
Cash flows from investing activities:
Investment in oil and gas properties		(234,776	)		(226,695	)		(10,833	)		—			(472,304	)
Proceeds from sale of oil and gas properties, net of expenses		6,300			—			—			—			6,300
Investment in fixed and other assets		(3,830	)		—			—			—			(3,830	)
Change in restricted funds		—			—			(2,394	)		—			(2,394	)
Investment in subsidiaries		(14,000	)		—			(13,404	)		27,404			—
Net cash used in investing activities		(246,306	)		(226,695	)		(26,631	)		27,404			(472,228	)
Cash flows from financing activities:
Deferred financing costs		(11	)		—			—			—			(11	)
Excess tax benefits		156			—			—			—			156
Equity proceeds from parent		—			—			27,404			(27,404	)		—
Net payments for share-based compensation		(3,733	)		—			—			—			(3,733	)
Net cash (used in) provided by financing activities		(3,588	)		—			27,404			(27,404	)		(3,588	)
Effect of exchange rate changes on cash		—			—			(145	)		—			(145	)
Net change in cash and cash equivalents		(37,205	)		114			640			—			(36,451	)
Cash and cash equivalents, beginning of period		228,398			51,128			—			—			279,526
Cash and cash equivalents, end of period	$	191,193		$	51,242		$	640		$	—		$	243,075

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2012

(In thousands)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities:
Net income (loss)	$	105,180		$	160,650			($75)			($160,575)	$	105,180
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		45,884			214,908			190			—		260,982
Accretion expense		423			24,246			257			—		24,926
Deferred income tax provision (benefit)		(30,793	)		90,366			—			—		59,573
Settlement of asset retirement obligations		—			(47,211	)		—			—		(47,211	)
Non-cash stock compensation expense		6,800			—			—			—		6,800
Excess tax benefits		(882	)		—			—			—		(882	)
Non-cash derivative income		—			(584	)		—			—		(584	)
Non-cash interest expense		9,068			—			—			—		9,068
Other non-cash expense		16			—								16
Change in current income taxes		(3,240	)		—			—			—		(3,240	)
Change in intercompany receivables/payables		207,166			(206,669	)		(497	)		—		—
(Increase) decrease in accounts receivable		(9,229	)		(6,631	)		28			—		(15,832	)
Increase in other current assets		(2,456	)		—			—			—		(2,456	)
Decrease in inventory		136			—			—			—		136
Increase (decrease) in accounts payable		5,733			422			(39	)		—		6,116
Decrease in other current liabilities		(20,441	)		(3,860	)		—			—		(24,301	)
Other		(163,921	)		(1,032	)		—			160,575		(4,378	)
Net cash provided by (used in) operating activities		149,444			224,605			(136	)		—		373,913
Cash flows from investing activities:
Investment in oil and gas properties		(240,877	)		(204,434	)		—			—		(445,311	)
Proceeds from sale of oil and gas properties, net of expenses		403			—			—			—		403
Sale of fixed assets		134			—			—			—		134
Investment in fixed and other assets		(3,998	)		—			—			—		(3,998	)
Net cash used in investing activities		(244,338	)		(204,434	)		—			—		(448,772	)
Cash flows from financing activities:
Proceeds from bank borrowings		25,000			—			—			—		25,000
Repayments of bank borrowings		(70,000	)		—			—			—		(70,000	)
Proceeds from issuance of senior convertible notes		300,000			—			—			—		300,000
Deferred financing costs of senior convertible notes		(8,855	)		—			—			—		(8,855	)
Proceeds from sold warrants		40,170			—			—			—		40,170
Payments for purchased call options		(70,830	)		—			—			—		(70,830	)
Excess tax benefits		882			—			—			—		882
Net payments for share-based compensation		(3,773	)		—			—			—		(3,773	)
Net cash provided by financing activities		212,594			—			—			—		212,594
Net change in cash and cash equivalents		117,700			20,171			(136	)		—		137,735
Cash and cash equivalents, beginning of period		37,389			926			136			—		38,451
Cash and cash equivalents, end of period	$	155,089		$	21,097		$	—		$	—	$	176,186

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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 2012 Annual Report on Form 10-K and in this Form 10-Q.

Forward-looking statements appear in a number of places in this Form 10-Q and include statements with respect to, among other things:

• any expected results or benefits associated with our acquisitions;

• expected results from risked weighted drilling success;

• estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production;

• planned capital expenditures and the availability of capital resources to fund capital expenditures;

• our outlook on oil and gas prices;

• estimates of our oil and 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 amount, nature and timing of any potential divestiture transactions;

• 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:

• commodity price volatility;

• consequences of a catastrophic event like the Deepwater Horizon oil spill;

• domestic and worldwide economic conditions;

• the availability of capital on economic terms to fund our capital expenditures and acquisitions;

• our level of indebtedness;

• 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;

• our ability to replace and sustain production;

• the impact of a financial crisis on our business operations, financial condition and ability to raise capital;

• the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

• third-party interruption of sales to market;

• inflation;

• lack of availability and cost of goods and services;

• market conditions relating to potential acquisition and divestiture transactions;

• regulatory and environmental risks associated with drilling and production activities;

• drilling and other operating risks;

• unsuccessful exploration and development drilling activities;

• hurricanes and other weather conditions;

• adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, including changes affecting our offshore and Appalachian operations; and

• uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures.

23

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 2012 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2012 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 2012 Annual Report on Form 10-K.

Overview

We are an independent oil and gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have expanded our reserve base outside of the conventional shelf of the Gulf of Mexico (the “GOM”) and into the more prolific reserve basins of the GOM deep water and Gulf Coast deep gas, as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia.

Critical Accounting Estimates

Our 2012 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:

• remaining proved oil and gas reserve volumes and the timing of their production;

• estimated costs to develop and produce proved oil and gas reserves;

• accruals of exploration costs, development costs, operating costs and production revenue;

• timing and future costs to abandon our oil and gas properties;

• effectiveness and estimated fair value of derivative positions;

• classification of unevaluated property costs;

• capitalized general and administrative costs and interest;

• insurance recoveries related to hurricanes and other events;

• estimates of fair value in business combinations;

• current and deferred income taxes; and

• contingencies.

This Form 10-Q should be read together with the discussion contained in our 2012 Annual Report on Form 10-K regarding these critical accounting policies.

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 2012 Annual Report on Form 10-K and in this Form 10-Q underPart II, Item 1A. Risk Factors, of this Form 10-Q regarding our known material risk factors.

Known Trends and Uncertainties

Hurricanes –Since the majority of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time. We have assumed all hurricane-related risk due to these rising insurance rates. 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 acceleration of plugging and abandonment costs.

Louisiana Franchise Taxes– We have been involved in litigation with the State of Louisiana over the proper computation of franchise taxes allocable to the state. This litigation relates to the state’s position that sales of crude oil and natural gas from properties located on the OCS, which are transported through the State of Louisiana, should be sourced to Louisiana for purposes of computing franchise taxes. We disagree with the state’s position. However, if the state’s position were to be upheld, we could incur additional expenses for alleged underpaid franchise taxes in prior years and higher franchise tax expense in future years. For additional information, seePart II, Item 1. Legal Proceedings, of this Form 10-Q.

24

Deep Water Operations – With our acquisition of interests in the Pompano field, we are now operating two significant properties in the deep water of the GOM. Additionally, we are engaged in deep water drilling operations. Operations in the deep water can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, 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 current losses on our statement of operations as well as going concern issues.

Non-U.S. Operations – In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Included in unevaluated oil and gas property costs at September 30, 2013 are $9.7 million of capital expenditures related to our oil and gas property investments in Canada. Under full cost accounting, investments in individual countries represent separate cost centers for computation of depreciation, depletion and amortization (“DD&A”) as well as for full cost ceiling test evaluations. Given that this is our sole investment in Canada, it is possible that upon a more complete evaluation of this project that some or all of this investment could be recognized as a charge to expense on our statement of operations.

Earnings Per Share– On March 6, 2012, we issued $300 million of 2017 Convertible Notes. These notes are convertible into cash, shares of our common stock or a combination thereof at our election. Current accounting standards require us to use the treasury method for determining potential dilution in our diluted earnings per share computation since it is management’s intention to settle the principal amount of the notes in cash. However, if due to changes in facts and circumstances beyond our control such intention were to change, or it becomes probable that we will be unable to settle the principal in cash, we could be required to change our methodology for determining fully diluted earnings per share to the if-converted method. The if-converted method would result in a substantial dilutive effect on diluted earnings per share when compared to the treasury method.

Sale of Shelf Properties – We have engaged a financial advisor to market certain of our properties in the GOM conventional shelf, state waters and onshore Louisiana. The properties represented approximately 12% of our total estimated proved reserves as of December 31, 2012. In October 2013, we completed the sale of our interest in the Weeks Island field, representing less than 1% of our total estimated proved reserves at December 31, 2012. Production volumes at the Weeks Island field represented approximately 2% of our total production volumes and 3% of our total production revenue for the nine months ended September 30, 2013. The remainder of our shelf properties that are subject to sale represented approximately 24% of our total production volumes and 21% of our total production revenue for the nine months ended September 30, 2013. The future sale of some or all of our shelf properties would be subject to an acceptable offer or offers and other market conditions.

Sales of oil and gas properties under the full cost method are accounted for as an adjustment to capitalized costs unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the applicable cost center. If such relationship would be altered significantly, we would be required to allocate the cost center between the properties sold and the properties retained and recognize a gain or loss on the sale in the period in which the transaction is consummated. The Weeks Island sale did not result in a significant alteration of this relationship and, consequently, no gain or loss will be recognized. Whether a significant alteration would occur on future transactions, and therefore a gain or loss recognized, cannot be determined at this time.

Liquidity and Capital Resources

At November 5, 2013, we had $378.5 million of availability under our bank credit facility and cash on hand of approximately $275 million. In September 2013, our capital expenditure budget for 2013 was increased from $650 million to $710 million. Most of the increase is in the GOM deep water, with minor increase in the Appalachia area. Our capital expenditure budget excludes material acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest. Based on our outlook of commodity prices and our estimated production, we expect our 2013 capital expenditures to exceed our cash flow from operating activities. We intend to finance our remaining capital expenditure budget with cash on hand and cash flow from operations.

Cash Flows and Working Capital.Net cash from operating activities totaled $439.5 million during the nine months ended September 30, 2013 compared to $373.9 million in the comparable period in 2012.

Net cash used in investing activities totaled $472.2 million and $448.8 million during the nine months ended September 30, 2013 and 2012, respectively, which primarily represents our investment in oil and natural gas properties.

Net cash used in financing activities totaled $3.6 million for the nine months ended September 30, 2013, which primarily represents net payments for share-based compensation. Net cash provided by financing activities totaled $212.6 million for the nine months ended September 30, 2012, which primarily represents $291.1 million of net proceeds from the issuance of the 2017 Convertible Notes and $40.1 million of proceeds from the Sold Warrants, partially offset by $70.8 million for the cost of the Purchased Call Options. Additionally, we had $25.0 million of borrowings and $70.0 million of repayments of borrowings under our bank credit facility during the nine months ended September 30, 2012.

We had working capital at September 30, 2013 of $237.0 million.

25

Capital Expenditures. During the three months ended September 30, 2013, additions to oil and gas property costs of $151.9 million included $17.5 million of lease and property acquisition costs, $8.5 million of capitalized SG&A expenses (inclusive of incentive compensation) and $11.9 million of capitalized interest. During the nine months ended September 30, 2013, additions to oil and gas property costs of $473.3 million included $79.4 million of lease and property acquisition costs, $22.6 million of capitalized SG&A expenses (inclusive of incentive compensation) and $32.8 million of capitalized interest. These investments were financed with cash on hand and cash flows from operations.

Bank Credit Facility.On April 26, 2011, we entered into an amended and restated revolving credit facility totaling $700 million through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On April 30, 2013, the bank group reaffirmed our existing borrowing base at $400 million. As of September 30 and November 5, 2013, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.5 million had been issued pursuant to our bank credit facility, leaving $378.5 million of availability under the facility. Our bank credit facility is guaranteed by our only material subsidiary, Stone Offshore.

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries 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. Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At our option, loans under our bank credit facility will bear interest at a rate based on the Libor Rate plus an applicable margin, or a rate based on the prime rate or federal funds rate plus an applicable margin.

Under the financial covenants of our bank credit facility, we must (1) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (2) 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 3.0 to 1. As of September 30, 2013, our debt to EBITDA ratio was 1.51 to 1 and our EBITDA to consolidated Net Interest Expense ratio was approximately 19.53 to 1. In addition, our bank credit facility includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership 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, 2013.

Contractual Obligations and Other Commitments

In addition to our significant contractual obligations and commitments summarized in our 2012 Annual Report on Form 10-K, in April 2013, we contracted two deep water drilling rigs for minimum total commitments of approximately $123.5 million to be incurred during the second half of 2013 and the first half of 2014. Additionally, in September 2013, we entered into a flowline agreement in excess of $70 million for the development of the Cardona deep water field, with project management and engineering work to commence immediately and offshore operations due to commence in the third quarter of 2014.

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Results of Operations

The following tables set forth certain information with respect to our oil and gas operations.

	Three Months Ended September 30,
	2013		2012		Variance			% Change
Production:
Oil (MBbls)		1,809		1,736		73			4	%
Natural gas (MMcf)		13,866		10,615		3,251			31	%
Natural gas liquids (“NGLs”) (MBbls)		425		341		84			25	%
Oil, natural gas and NGLs (MMcfe)		27,270		23,077		4,193			18	%
Revenue data (in thousands) (a):
Oil revenue	$	186,608	$	180,806	$	5,802			3	%
Natural gas revenue		52,728		34,003		18,725			55	%
NGLs revenue		16,476		11,910		4,566			38	%
Total oil, natural gas and NGL revenue	$	255,812	$	226,719	$	29,093			13	%
Average prices (a):
Oil (per Bbl)	$	103.16	$	104.15	($	0.99	)		(1	%)
Natural gas (per Mcf)		3.80		3.20		0.60			19	%
NGLs (per Bbl)		38.77		34.93		3.84			11	%
Oil, natural gas and NGLs (per Mcfe)		9.38		9.82		(0.44	)		(4	%)
Expenses (per Mcfe):
Lease operating expenses	$	1.98	$	2.64	($	0.66	)		(25	%)
SG&A expenses (b)		0.52		0.59		(0.07	)		(12	%)
DD&A expense on oil and gas properties		3.37		3.83		(0.46	)		(12	%)

(a) Includes the cash settlement of effective hedging contracts.

(b) Excludes incentive compensation expense.

	Nine Months Ended September 30,
	2013		2012		Variance			% Change
Production:
Oil (MBbls)		5,243		5,289		(46	)		(1	%)
Natural gas (MMcf)		35,969		31,031		4,938			16	%
NGLs (MBbls)		1,048		794		254			32	%
Oil, natural gas and NGLs (MMcfe)		73,715		67,529		6,186			9	%
Revenue data (in thousands) (a):
Oil revenue	$	558,031	$	564,745	($	6,714	)		(1	%)
Natural gas revenue		137,382		91,006		46,376			51	%
NGLs revenue		36,854		35,228		1,626			5	%
Total oil, natural gas and NGL revenue	$	732,267	$	690,979	$	41,288			6	%
Average prices (a):
Oil (per Bbl)	$	106.43	$	106.78	($	0.35	)		(0.3	%)
Natural gas (per Mcf)		3.82		2.93		0.89			30	%
NGLs (per Bbl)		35.17		44.37		(9.20	)		(21	%)
Oil, natural gas and NGLs (per Mcfe)		9.93		10.23		(0.30	)		(3	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.14	$	2.33	($	0.19	)		(8	%)
SG&A expenses (b)		0.59		0.60		(0.01	)		(2	%)
DD&A expense on oil and gas properties		3.43		3.83		(0.40	)		(10	%)

(a) Includes the cash settlement of effective hedging contracts.

(b) Excludes incentive compensation expense.

Net Income. During the three months ended September 30, 2013, we reported net income totaling $36.1 million, or $0.72 per share, compared to net income for the three months ended September 30, 2012 of $23.7 million, or $0.48 per share. During the nine months ended September 30, 2013, we reported net income totaling $115.9 million, or $2.32 per share, compared to net income for the nine months ended September 30, 2012 of $105.2 million, or $2.13 per share. All per share amounts are on a diluted basis.

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The variance in the three and nine month periods’ results was due to the following components:

Production.During the three months ended September 30, 2013, total production volumes increased to 27.3 Bcfe compared to 23.1 Bcfe produced during the comparable 2012 period, representing an 18% increase. Oil production during the three months ended September 30, 2013 totaled approximately 1,809,000 Bbls compared to 1,736,000 Bbls produced during the comparable 2012 period. Natural gas production totaled 13.9 Bcf during the three months ended September 30, 2013 compared to 10.6 Bcf during the comparable 2012 period. NGL production during the three months ended September 30, 2013 totaled approximately 425,000 Bbls compared to 341,000 Bbls produced during the comparable 2012 period.

During the nine months ended September 30, 2013, total production volumes increased to 73.7 Bcfe compared to 67.5 Bcfe produced during the comparable 2012 period, representing a 9% increase. Oil production during the nine months ended September 30, 2013 totaled approximately 5,243,000 Bbls compared to 5,289,000 Bbls produced during the nine months ended September 30, 2012. Natural gas production totaled 36.0 Bcf during the nine months ended September 30, 2013 compared to 31.0 Bcf during the comparable 2012 period. NGL production during the nine months ended September 30, 2013 totaled approximately 1,048,000 Bbls compared to 794,000 Bbls produced during the comparable 2012 period.

During the three months ended September 30, 2013, seven new wells in the Mary field were brought online. During the three months ended June 30, 2013, the third well in the La Cantera field was placed on production. Also during the three months ended June 30, 2013, the Williams pipeline was repaired and pressure restrictions were eliminated, which allowed us to restore shut-in production in the Mary field.

Prices. Prices realized during the three months ended September 30, 2013 averaged $103.16 per Bbl of oil, $3.80 per Mcf of natural gas and $38.77 per Bbl of NGLs, or 4% lower, on an Mcfe basis, than average realized prices of $104.15 per Bbl of oil, $3.20 per Mcf of natural gas and $34.93 per Bbl of NGLs during the comparable 2012 period. Prices realized during the nine months ended September 30, 2013 averaged $106.43 per Bbl of oil, $3.82 per Mcf of natural gas and $35.17 per Bbl of NGLs, or 3% lower, on an Mcfe basis, than average realized prices of $106.78 per Bbl of oil, $2.93 per Mcf of natural gas and $44.37 per Bbl of NGLs during the comparable 2012 period. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. Our effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and decreased our average realized oil price by $4.14 per Bbl during the three months ended September 30, 2013. During the three months ended September 30, 2012, our effective hedging transactions increased our average realized natural gas price by $0.55 per Mcf and increased our average realized oil price by $2.34 per Bbl. During the nine months ended September 30, 2013, effective hedging transactions increased our average realized natural gas price by $0.32 per Mcf and increased our average realized oil price by $0.45 per Bbl. During the nine months ended September 30, 2012, effective hedging transactions increased our average realized natural gas price by $0.55 per Mcf and increased our average realized oil price by $0.21 per Bbl.

Revenue.Oil, natural gas and NGL revenue was $255.8 million during the three months ended September 30, 2013 compared to $226.7 million during the comparable period of 2012. The increase was attributable to an 18% increase in production quantities on a gas equivalent basis, which was partially offset by a 4% decrease in average realized prices. For the nine months ended September 30, 2013 and 2012, oil, natural gas and NGL revenue totaled $732.3 million and $691.0 million, respectively. The increase was attributable to a 9% increase in production quantities on a gas equivalent basis, which was partially offset by a 3% decrease in average realized prices.

Expenses.Lease operating expenses during the three months ended September 30, 2013 and 2012 totaled $54.0 million and $61.0 million, respectively. For the nine months ended September 30, 2013 and 2012, lease operating expenses totaled $157.5 million and $157.0 million, respectively. The decrease in lease operating expenses during the three months ended September 30, 2013, compared to the three months ended September 30, 2012, was attributable to a decrease in insurance and major maintenance expenses.

Transportation, processing and gathering expenses during the three months ended September 30, 2013 and 2012 totaled $13.1 million and $6.8 million, respectively. For the nine months ended September 30, 2013 and 2012, transportation, processing and gathering expenses totaled $27.4 million and $15.9 million, respectively. The increase is attributable to higher gas and NGL volumes and short term blending fees in Appalachia, as well as higher GOM pipeline fees.

DD&A expense on oil and gas properties for the three months ended September 30, 2013 totaled $91.9 million, or $3.37 per Mcfe, compared to $88.4 million, or $3.83 per Mcfe, during the comparable period of 2012. For the nine months ended September 30, 2013 and 2012, DD&A expense totaled $252.8 million, or $3.43 per Mcfe, and $258.6 million, or $3.83 per Mcfe, respectively.

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SG&A expenses (exclusive of incentive compensation) for the three months ended September 30, 2013 were $14.2 million compared to $13.7 million for the three months ended September 30, 2012. For the nine months ended September 30, 2013 and 2012, SG&A expenses (exclusive of incentive compensation) totaled $43.4 million and $40.5 million, respectively. The increase in SG&A expenses for the nine months ended September 30, 2013 was primarily the result of increased staffing and compensation adjustments (including share-based compensation). Partially offsetting this increase was a reimbursement of $1.6 million of legal fees relating to the settlement of litigation in prior periods. Included in SG&A expenses during the nine months ended September 30, 2012 was a management fee of $1.0 million for transition services related to the Pompano field acquisition.

For the three months ended September 30, 2013 and 2012, incentive compensation expense totaled $4.6 million and $0.1 million, respectively. For the nine months ended September 30, 2013 and 2012, incentive compensation expense totaled $8.0 million and $3.9 million, respectively. These amounts relate to the accrual of estimated incentive compensation bonuses calculated based on the projected achievement of certain strategic objectives for each fiscal year.

Interest expense for the three months ended September 30, 2013 totaled $7.9 million, net of $11.9 million of capitalized interest, compared to interest expense of $7.7 million, net of $9.5 million of capitalized interest, during the comparable 2012 period. For the nine months ended September 30, 2013, interest expense totaled $26.5 million, net of $32.8 million of capitalized interest, compared to interest expense of $21.1 million, net of $27.7 million of capitalized interest, during the comparable 2012 period. The increase in interest expense was primarily the result of interest associated with the 2022 Notes issued in November 2012 and the 2017 Convertible Notes issued in March 2012. Partially offsetting these increases was a decrease in interest expense as a result of the redemption in December 2012 of our 6 ³⁄₄% Senior Subordinated Notes due 2014.

Off-Balance Sheet Arrangements

None.

Recent Accounting Developments

None.

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. MMBtu represents one million British Thermal Units, and BBtu represents one billion 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. In order to manage our exposure to oil and natural gas price declines, we occasionally enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

Our hedging policy provides that not more than 50% of our estimated production quantities can be hedged for any given year without the consent of our Board of Directors. We believe our current hedging positions have hedged approximately 48% of our estimated 2013 production from estimated proved reserves, 46% of our estimated 2014 production from estimated proved reserves and 17% of our estimated 2015 production from estimated proved reserves. See Part I, Item 1. Financial Statements – Note 3 – 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 2012 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 $975 million at September 30, 2013, all of which bears interest at fixed rates. The $975 million of fixed-rate debt is comprised of $300 million face value of the 2017 Convertible Notes, $375 million of the 2017 Notes and $300 million of the 2022 Notes.

Our bank credit facility is subject to an adjustable interest rate. SeePart I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resourcesof this Form 10-Q. We had no outstanding borrowings under our bank credit facility as of September 30, 2013. If we borrow funds under our bank credit facility, we may be subject to increased sensitivity to interest rate movements.

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, 2013 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, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

On December 30, 2004, we were served with two petitions (civil action numbers 2004-6227 and 2004-6228) filed by the LDR in the 15th Judicial District Court (Parish of Lafayette, Louisiana) claiming additional franchise taxes due. In one case, the LDR is seeking additional franchise taxes from Stone in the amount of $640,000, plus accrued interest of $352,000 (calculated through December 15, 2004), for the franchise tax year 2001. In the other case, the LDR is seeking additional franchise taxes from Stone (as successor to Basin Exploration, Inc.) in the amount of $274,000, plus accrued interest of $159,000 (calculated through December 15, 2004), for the franchise tax years 1999, 2000 and 2001. On December 29, 2005, the LDR filed another petition (civil action number 2005-6524) in the 15th Judicial District Court claiming additional franchise taxes due for the franchise tax years 2002 and 2003 in the amount of $2.6 million, plus accrued interest of $1.2 million (calculated through December 15, 2005). Also, on January 2, 2008, we were served with a petition (civil action number 2007-6754) in the 15th Judicial District Court claiming $1.5 million of additional franchise taxes due for the franchise tax year 2004, plus accrued interest of $800,000 (calculated through November 30, 2007). Further, on January 7, 2009, we were served with a petition (civil action number 2008-7193) in the 15th Judicial District Court claiming additional franchise taxes due for the franchise tax years 2005 and 2006 in the amount of $4.0 million, plus accrued interest of $1.7 million (calculated through October 21, 2008). In addition, we have received proposed assessments from the LDR for additional franchise taxes in the amount of $8.1 million resulting from audits of Stone and our subsidiaries. These petitions and assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the OCS, which are transported through the State of Louisiana, should be sourced to the State of Louisiana for purposes of computing the Louisiana franchise tax apportionment ratio. We disagree with these contentions and are vigorously defending ourselves against these claims. The franchise tax years 2010, 2011 and 2012 for Stone remain subject to examination.

In October 2012, we received a notice from the Bureau of Safety and Environmental Enforcement (“BSEE”) that it was initiating an enforcement proceeding with respect to an Incident of Non-Compliance observed at our Vermillion Block 255 Platform H in April 2012. We believe that the conditions observed were not actually violations of applicable rules and accordingly initiated discussions with BSEE to resolve the matter. Notwithstanding these discussions, by “Reviewing Officer’s Final Decision” dated July 9, 2013, BSEE assessed a penalty against Stone of $200,000 based on $25,000 per day for eight days of alleged improper venting of gas at the platform. We are pursuing an administrative appeal of this decision. We do not believe that this proceeding will have a material adverse effect on our financial condition or results of operations.

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In December 2011, a slope failure occurred adjacent to a well pad where we were drilling a well in Wetzel County, West Virginia. The slope failure was near a stream, and an estimated 250 to 300 cubic yards of soil and debris entered the stream. We responded to the incident by removing the discharged material from the stream and stabilizing the area in which the slope failure occurred. In October 2013, we received notice from the West Virginia Department of Environmental Protection that it was proposing to impose a penalty on us for an unauthorized discharge of pollutants into the affected stream. We are currently discussing the proposed terms of a consent order with the agency to resolve this matter, but we do not expect that the terms of any order or the amount of any fine will have a material adverse effect on our operations or financial condition.

Litigation is 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 these matters and are unable to estimate a range of possible losses or any minimum loss from such matters.

Item 1A. Risk Factors

The following risk factor updates the Risk Factors included in our 2012 Annual Report on Form 10-K. Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of our 2012 Annual Report on Form 10-K.

We may not be insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, oil pollution, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages and/or losses.

Effective May 1, 2013, we no longer purchase physical damage insurance coverage for our platforms for losses resulting from named windstorms. Additionally, we now purchase physical damage insurance coverage for losses resulting from operational activities for only our Amberjack and Pompano platforms. We have continued purchasing physical damage insurance coverage for operational losses for a selected group of pipelines including the pipelines and umbilicals associated with our Amberjack and Pompano facilities. In addition, effective July 1, 2013, we increased our general liability insurance coverage to an annual aggregate limit of $725 million on a 100% working interest basis.

Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20 million to $300 million per occurrence. Exploratory deep water wells have a coverage limit of $600 million per occurrence. Additionally, we maintain $150 million in oil pollution liability coverage, including $70 million of self-insurance. Our general liability, operational control of well and physical damage policy limits are scaled proportionately to our working interests, and all of our policies described above are subject to deductibles, sub-limits and/or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

An operational event in excess of our coverage or a hurricane-related event may cause damage or liability that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also severely impact our financial position. In past years, we have experienced production interruptions for which we had no production interruption insurance.

We reevaluate the purchase of insurance, policy limits and terms annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the GOM, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

31

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 were withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the three months ended September 30, 2013:

Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
July 1 – July 31, 2013		5,722	$	22.44		—
August 1 – August 31, 2013		508		28.18		—
September 1 – September 30, 2013		—		—		—
		6,230	$	22.90		—	$	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. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program.

(2) On September 24, 2007, our Board of Directors authorized a share repurchase program for an aggregate amount of up to $100 million in common stock. 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.

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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 filed August 7, 2012 (File No. 001-12074)).
3.2	Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)).
10.1	Amendment No. 3 dated as of April 30, 2013 to the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed May 8, 2013 (File No. 001-12074)).
*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.

33

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 6, 2013	By:	/s/ J. Kent Pierret
		J. Kent Pierret
		Senior Vice President,
		Chief Accounting Officer and Treasurer
		(On behalf of the Registrant and as
		Chief Accounting Officer)

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	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 filed August 7, 2012 (File No. 001-12074)).
3.2	Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)).
10.1	Amendment No. 3 dated as of April 30, 2013 to the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed May 8, 2013 (File No. 001-12074)).
*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.

35