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10-Q 1 d404752d10q.htm FORM 10-Q Form 10-Q

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, 2012

¨	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.

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 2, 2012, there were 49,503,454 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, 2012 and December 31, 2011		1
	Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2012 and 2011		2
	Condensed Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011		3
	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2012 and 2011		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		30
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		31
Item 3.	Defaults Upon Senior Securities		Not Applicable
Item 4.	Mine Safety Disclosures		Not Applicable
Item 5.	Other Information		Not Applicable
Item 6.	Exhibits		32
	Signature		35

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	September 30,			December 31,
	2012			2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	176,186		$	38,451
Accounts receivable		127,250			118,139
Fair value of hedging contracts		34,010			25,177
Current income tax receivable		24,066			19,946
Deferred taxes		12,280			26,072
Inventory		4,506			4,643
Other current assets		3,246			791

Total current assets		381,544			233,219
Oil and gas properties, full cost method of accounting:
Proved		7.039.450			6,648,168
Less: accumulated depreciation, depletion and amortization		(5,427,668	)		(5,174,729	)

Net proved oil and gas properties		1,611,782			1,473,439
Unevaluated		454,639			401,609
Other property and equipment, net		13,399			11,172
Fair value of hedging contracts		18,155			22,543
Other assets, net		35,158			23,769

Total assets	$	2,514,677		$	2,165,751

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	99,362		$	102,946
Undistributed oil and gas proceeds		24,277			27,328
Accrued interest		9,774			14,059
Fair value of hedging contracts		1,077			11,122
Asset retirement obligations		59,366			62,676
Other current liabilities		11,405			28,370

Total current liabilities		205,261			246,501
Long-term debt		811,024			620,000
Deferred taxes		298,100			247,835
Asset retirement obligations		351,023			363,103
Fair value of hedging contracts		2,266			815
Other long-term liabilities		20,844			19,668

Total liabilities		1,688,518			1,497,922

Commitments and contingencies

Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 48,390,463 and 48,076,860 shares, respectively		484			481
Treasury stock (16,582 shares, at cost)		(860	)		(860	)
Additional paid-in capital		1,383,741			1,338,565
Accumulated deficit		(587,045	)		(692,225	)
Accumulated other comprehensive income		29,839			21,868

Total stockholders’ equity		826,159			667,829

Total liabilities and stockholders’ equity	$	2,514,677		$	2,165,751

The accompanying notes are an integral part of this statement.

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,
	2012			2011			2012			2011
Operating revenue:
Oil production	$	180,806		$	157,436		$	564,745		$	484,788
Gas production		34,003			42,771			91,006			131,815
Natural gas liquids production		11,910			9,060			35,228			25,290
Other operational income		678			1,245			2,520			2,994
Derivative income, net		—			4,082			3,119			3,300

Total operating revenue		227,397			214,594			696,618			648,187

Operating expenses:
Lease operating expenses		60,995			46,591			157,030			130,486
Transportation, processing and gathering expenses		6,762			2,763			15,911			7,311
Other operational expenses		82			654			195			1,452
Production taxes		1,842			2,492			7,578			6,828
Depreciation, depletion and amortization		89,274			64,462			260,982			204,777
Accretion expense		8,405			7,700			24,926			23,134
Salaries, general and administrative expenses		13,673			7,151			40,521			29,494
Incentive compensation expense		67			2,087			3,907			7,104
Derivative expense, net		1,812			—			—			—

Total operating expenses		182,912			133,900			511,050			410,586

Income from operations		44,485			80,694			185,568			237,601

Other (income) expenses:
Interest expense		7,692			1,379			21,107			6,470
Interest income		(117	)		(23	)		(227	)		(170	)
Other income		(443	)		(372	)		(1,229	)		(1,499	)
Loss on early extinguishment of debt		—			—			—			607
Other expense		—			308			—			501

Total other expenses		7,132			1,292			19,651			5,909

Net income before income taxes		37,353			79,402			165,917			231,692

Provision (benefit) for income taxes:
Current		595			(12,681	)		1,164			(15,043	)
Deferred		13,099			40,262			59,573			97,926

Total income taxes		13,694			27,581			60,737			82,883

Net income	$	23,659		$	51,821		$	105,180		$	148,809

Basic earnings per share	$	0.48		$	1.06		$	2.13		$	3.04
Diluted earnings per share	$	0.48		$	1.06		$	2.13		$	3.04

Average shares outstanding		48,342			48,029			48,300			47,963
Average shares outstanding assuming dilution		48,384			48,071			48,343			48,006

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Net income	$	23,659		$	51,821	$	105,180	$	148,809
Other comprehensive income (loss), net of tax effect: Adjustment for fair value accounting of derivatives		(33,166	)		76,007		7,971		79,645

Comprehensive income (loss)	($	9,507	)	$	127,828	$	113,151	$	228,454

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands of dollars)

(Unaudited)


	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	105,180		$	148,809
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		260,982			204,777
Accretion expense		24,926			23,134
Deferred income tax provision		59,573			97,926
Settlement of asset retirement obligations		(47,211	)		(52,543	)
Non-cash stock compensation expense		6,800			4,492
Excess tax benefits		(882	)		(1,490	)
Non-cash derivative income		(584	)		(4,337	)
Loss on early extinguishment of debt		—			607
Non-cash interest expense		9,068			1,412
Other non-cash (income) expense		16			(1,362	)
Change in current income taxes		(3,240	)		(21,710	)
Increase in accounts receivable		(15,832	)		(17,117	)
Increase in other current assets		(2,456	)		(185	)
Decrease in inventory		136			1,606
Increase in accounts payable		6,116			2,679
Increase (decrease) in other current liabilities		(24,301	)		3,604
Other		(4,378	)		(1,889	)

Net cash provided by operating activities		373,913			388,413

Cash flows from investing activities:
Investment in oil and gas properties		(445,311	)		(430,711	)
Proceeds from sale of oil and gas properties, net of expenses		403			7,692
Sale of fixed assets		134			—
Investment in fixed and other assets		(3,998	)		(1,788	)

Net cash used in investing activities		(448,772	)		(424,807	)

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			—
Financing costs of senior convertible notes		(8,855	)		—
Proceeds from Sold Warrants		40,170			—
Payments for Purchased Call Options		(70,830	)		—
Deferred financing costs		—			(4,017	)
Excess tax benefits		882			1,490
Net payments for share based compensation		(3,773	)		(2,581	)

Net cash provided by (used in) financing activities		212,594			(5,108	)

Net change in cash and cash equivalents		137,735			(41,502	)
Cash and cash equivalents, beginning of period		38,451			106,956

Cash and cash equivalents, end of period	$	176,186		$	65,454

The accompanying notes are an integral part of this statement.

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, 2012 and for the three and nine-month periods ended September 30, 2012 and 2011 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, 2011 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, 2011 (“2011 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 2011 Annual Report on Form 10-K. The results of operations for the three and nine-month periods ended September 30, 2012 are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

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,
	2012			2011			2012			2011
	(in thousands, except per share data)
Income (numerator):
*Basic:*
Net income	$	23,659		$	51,821		$	105,180		$	148,809
Net income attributable to participating securities		(540	)		(976	)		(2,404	)		(2,807	)

Net income attributable to common stock – basic	$	23,119		$	50,845		$	102,776		$	146,002

*Diluted:*
Net income	$	23,659		$	51,821		$	105,180		$	148,809
Net income attributable to participating securities		(540	)		(975	)		(2,402	)		(2,805	)

Net income attributable to common stock – diluted	$	23,119		$	50,846		$	102,778		$	146,004

Weighted average shares (denominator):
Weighted average shares – basic		48,342			48,029			48,300			47,963
Diluted effect of stock options		42			42			43			43

Weighted average shares – diluted		48,384			48,071			48,343			48,006

Basic income per common share	$	0.48		$	1.06		$	2.13		$	3.04

Diluted income per common share	$	0.48		$	1.06		$	2.13		$	3.04

Stock options that were considered antidilutive because the exercise price of the option exceeded the average price of our common stock for the applicable period totaled approximately 369,000 and 376,000 shares for the three and nine-month periods ended September 30, 2012 and 2011, respectively.

During each of the three-month periods ended September 30, 2012 and 2011, respectively, approximately 59,000 shares of common stock were issued upon the vesting of restricted stock by employees and nonemployee directors. During the nine months ended September 30, 2012 and 2011, respectively, approximately 314,000 and 312,000 shares of common stock were issued upon the vesting of restricted stock by employees and nonemployee directors.

Because it is management’s stated intention to redeem the principal amount of our 1³/₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) (see Note 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 in Note 4 – Long-Term Debt) for the reporting period, such warrants were also not dilutive for such period.

Note 3 – Derivative Instruments and Hedging Activities

Our hedging strategy is designed to protect our near and intermediate term cash flow 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 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 the balance sheet at fair value and changes in fair value are recognized in earnings through derivative expense (income). 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 indicated in the derivative contracts. Monthly settlements of ineffective hedges are recognized in earnings through derivative expense (income) and cash flows from operations.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2012, 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 (“WTI”) during the entire calendar month, and some are based on the average of the Intercontinental Exchange (“ICE”) 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 and Natixis.

All of our derivative instruments at September 30, 2012 and December 31, 2011 were designated as effective cash flow hedges; however, during the nine-month periods ended September 30, 2012 and 2011, 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, 2012 and December 31, 2011.


Fair Value of Derivative Instruments at September 30, 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	$	34.0	Current liabilities: Fair value of hedging contracts	($	1.1	)
	Long-term assets: Fair value of hedging contracts		18.2	Long-term liabilities: Fair value of hedging contracts		(2.3	)

		$	52.2		($	3.4	)


Fair Value of Derivative Instruments at December 31, 2011
(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	$	25.2	Current liabilities: Fair value of hedging contracts	($	11.1	)
	Long-term assets: Fair value of hedging contracts		22.5	Long-term liabilities: Fair value of hedging contracts		(0.8	)

		$	47.7		($	11.9	)

The following tables disclose the effect of derivative instruments in the statement of operations for the three and nine-month periods ended September 30, 2012 and 2011.


The Effect of Derivative Instruments on the Statement of Operations for the Three Months Ended September 30, 2012 and 2011 (in millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI on Derivatives (a)					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) (b)					Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2012			2011		Location	2012		2011		Location	2012			2011
Commodity contracts	($	33.2	)	$	76.0	Operating revenue – oil/gas production	$	10.0	$	1.3	Derivative income (expense), net	($	1.8	)	$	4.1

Total	($	33.2	)	$	76.0		$	10.0	$	1.3		($	1.8	)	$	4.1

(a)	Net of related tax effect of ($19.2) million and $40.4 million for the three months ended September 30, 2012 and 2011, respectively.

(b)

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. For the three months ended September 30, 2011, effective hedging contracts decreased oil revenue by $3.3 million and increased gas revenue by $4.6 million.


The Effect of Derivative Instruments on the Statement of Operations for the Nine Months Ended September 30, 2012 and 2011 (in millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI on Derivatives (a)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) (b)						Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2012		2011		Location	2012		2011			Location	2012		2011
Commodity contracts	$	7.9	$	79.6	Operating revenue – oil/gas production	$	18.4	($	13.1	)	Derivative income, net	$	3.1	$	3.3

Total	$	7.9	$	79.6		$	18.4	($	13.1	)		$	3.1	$	3.3

(a)	Net of related tax effect of $4.6 million and $44.4 million for the nine months ended September 30, 2012 and 2011, respectively.

(b)

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. For the nine months ended September 30, 2011, effective hedging contracts decreased oil revenue by $26.1 million and increased gas revenue by $13.0 million.

At September 30, 2012, we had accumulated other comprehensive income of $29.8 million, net of tax, which related to the fair value of our swap contracts that were outstanding as of September 30, 2012. We believe that approximately $19.9 million of the accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

The following table illustrates our hedging positions for calendar years 2012, 2013, 2014 and 2015 as of November 2, 2012:


	Fixed-Price Swaps NYMEX (except where noted)
	Natural Gas				Oil
	Daily Volume (MMBtus/d)		Swap Price ($)		Daily Volume (Bbls/d)			Swap Price ($)
2012		10,000		5.035		1,000			90.30
2012		10,000		5.040		1,000			90.41
2012		10,000		5.050		1,000			90.45
2012						1,000			95.50
2012						2,000			97.60
2012						1,000			98.15
2012						1,000			100.00
2012						1,000			101.55
2012						1,000			104.25
2012						1,000	*		111.02

2013		10,000		4.000		1,000			92.80
2013		10,000		5.270		2,000	**		94.05
2013		10,000		5.320		1,000			94.45
2013						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	*		107.30

2014		10,000		4.000		1,000			90.06
2014		10,000		4.250		1,000			93.55
2014						1,000			98.00
2014						1,000			98.30
2014						1,000			99.65
2014						1,000	*		103.30

2015		10,000		4.005		1,000			90.00

*	Brent oil contract

**	January through June

Note 4 – Long-Term Debt

Long-term debt consisted of the following at:


	September 30, 2012		December 31, 2011
	(in millions)
6³/₄% Senior Subordinated Notes due 2014	$	200.0	$	200.0
8⁵/₈% Senior Notes due 2017		375.0		375.0
1³/₄% Senior Convertible Notes due 2017		236.0		—
Bank debt		—		45.0

Total long-term debt	$	811.0	$	620.0

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 September 15, 2014. However, if the 6³/₄% Senior Subordinated Notes due 2014 (the “2014 Notes”) issued under our 2004 indenture are retired on or before April 15, 2014, our bank credit facility will mature on April 26, 2015. On

October 22, 2012, the borrowing base under our bank credit facility was reaffirmed at $400 million. As of September 30 and November 2, 2012, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.0 million had been issued pursuant to the bank credit facility, leaving $379.0 million of availability under the facility. Our bank credit facility is guaranteed by our only subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

On October 22, 2012, we commenced a public offering of $300 million in aggregate principal amount of Senior Notes due 2022 (the “2022 Notes”) (see Note 10 – Subsequent Events). On October 22, 2012, we entered into an amendment and obtained a consent from our lenders, which (1) provides that the borrowing base under our bank credit facility will not be reduced as a result of the issuance of the 2022 Notes; provided, however, that, if the 2022 Notes are issued, to the extent that the 2014 Notes in an aggregate principal amount equal to $200 million shall not have been repurchased, repaid, defeased or otherwise retired on or prior to December 31, 2012, the borrowing base will be reduced automatically on December 31, 2012 by an amount equal to 30% of the difference between $200 million and the aggregate principal amount of 2014 Notes so repurchased, repaid, defeased or otherwise retired, and (2) increases our basket for outstanding notes from $900 million in the aggregate to $1.25 billion on or prior to December 31, 2012, and to $1.1 billion at any time thereafter.

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 London Interbank Offered Rate (“Libor”) 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, 2012.

6³/₄% Senior Subordinated Notes due 2014

On October 22, 2012, we commenced a cash tender offer and consent solicitation with respect to any and all of the $200 million aggregate outstanding principal amount of our 2014 Notes (see Note 10 – Subsequent Events).

Senior Convertible Notes

On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of 1³/₄% Senior Convertible Notes due 2017 to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the sale of the 2017 Convertible Notes were approximately $291.1 million, after deducting fees and expenses. The 2017 Convertible Notes rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 2017 Convertible Notes are effectively subordinated to our secured indebtedness to the extent of the value of the related collateral. The 2017 Convertible Notes bear interest at a rate of 1.75% per year, payable on March 1 and September 1 of each year, beginning on September 1, 2012. The 2017 Convertible Notes mature on March 1, 2017, unless earlier converted or repurchased. We may not redeem the 2017 Convertible Notes at our option prior to the maturity date.

The 2017 Convertible Notes may be converted by the holder, in multiples of $1,000 principal amount, only under the following circumstances:

•

prior to December 1, 2016, on any date during any calendar quarter beginning after June 30, 2012 (and only during such calendar quarter) if the closing sale price of our common stock was more than 130% of the then current conversion price for at least 20 trading days in the period of the 30 consecutive trading days ending on the last trading day of the previous calendar quarter;

•

prior to December 1, 2016, if we distribute to all or substantially all holders of our common stock rights, options or warrants entitling them to purchase, for a period of 45 calendar days or less from the declaration date for such distribution, shares of our common stock at a price per share less than the average closing sale price of our common stock for the ten consecutive trading days immediately preceding, but excluding, the declaration date for such distribution;

•

prior to December 1, 2016, if we distribute to all or substantially all holders of our common stock cash, other assets, securities or rights to purchase our securities, which distribution has a per share value exceeding 10% of the closing sale price of our common stock on the trading day immediately preceding the declaration date for such distribution, or if we engage in certain corporate transactions described in the indenture related to the 2017 Convertible Notes;

•

prior to December 1, 2016, during the five consecutive business-day period following any five consecutive trading-day period in which the trading price per $1,000 principal amount of 2017 Convertible Notes for each trading day during such five trading-day period was less than 98% of the closing sale price of our common stock for each trading day during such five trading-day period multiplied by the then current conversion rate; or

•

on or after December 1, 2016, and prior to the close of business on the second scheduled trading day immediately preceding the maturity date of the 2017 Convertible Notes, which is March 1, 2017, without regard to the foregoing conditions.

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

If we undergo a fundamental change (as defined in the indenture related to the 2017 Convertible Notes) prior to maturity, holders of the 2017 Convertible Notes will have the right, at their option, to require us to repurchase for cash some or all of their 2017 Convertible Notes at a repurchase price equal to 100% of the principal amount of the 2017 Convertible Notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.

If holders elect to convert the 2017 Convertible Notes in connection with certain fundamental change transactions described in the indenture related to the 2017 Convertible Notes, we will increase the conversion rate by a number of additional shares determined by reference to the provisions contained in the indenture related to the 2017 Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of our common stock in, such make-whole fundamental change. If holders of our common stock receive only cash in connection with certain make-whole fundamental changes, the price paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the closing sale prices of our common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.

In connection with the sale of the 2017 Convertible Notes, 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 anti-dilution 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 anti-dilution adjustments, approximately 7,033,470 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91 per share of 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.

The Purchased Call Options and Sold Warrants are separate contracts entered into by Stone and each of the Dealers, are not part of the terms of the 2017 Convertible Notes and will not affect the holders’ rights under the 2017 Convertible Notes. The Purchased Call Options are expected generally to reduce the potential dilution upon conversion of the 2017 Convertible Notes in the event that the market value per share of our common stock at the time of exercise is greater than the strike price of the Purchased Call Options. The Sold Warrants could separately have a dilutive effect to the extent that the market value per share of our common stock exceeds the applicable strike price of the Sold Warrants.

The estimated liability and equity components of this offering were recorded in accordance with Accounting Standards Codification (“ASC”) 470-20. The initial carrying amount of the liability component of $229.2 million was determined by measuring the fair value of a similar liability that does not have an associated equity component. An effective market interest rate of 7.51% was used in the fair value determination. The carrying amount of the equity component of $70.8 million was determined by deducting the fair value of the liability component from the initial proceeds from the 2017 Convertible Notes. Transaction costs of approximately $8.9 million were allocated to the liability and equity components in proportion to the allocation of proceeds and accounted for as debt issuance and equity issuance costs, respectively. The cost of the convertible note hedge of $70.8 million and proceeds from the warrant transaction of $40.1 million were recorded as adjustments to equity. A summary of the entries to record the proceeds from the 2017 Convertible Notes, the cost of the Purchased Call Options and the proceeds from the Sold Warrants is as follows (in millions):


Cash	$	260.5
Other assets (deferred financing costs)		6.8
Long-term debt		(229.2	)
Additional paid-in capital		(38.1	)

Note 5 – Asset Retirement Obligations

The change in our asset retirement obligations during the nine months ended September 30, 2012 is set forth below:


	Nine Months Ended September 30, 2012
	(in millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	425.8
Liabilities settled		(47.2	)
Liabilities assumed		14.5
Divestment of properties		(7.6	)
Accretion expense		24.9

Asset retirement obligations as of the end of the period, including current portion	$	410.4

Note 6 – Acquisitions

On June 18, 2012, we completed the acquisition of Anadarko U.S. Offshore Corporation’s (“APC”) 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, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value (see Note 7 – Fair Value Measurements). Differences between the net fair value of assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain. The following represents the allocation of the recorded value of net assets acquired in the transaction. Consideration transferred in the transaction was $26.4 million in cash, resulting in no goodwill or bargain purchase gain.


	(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

On December 28, 2011, we completed the acquisition of BP Exploration & Production Inc.’s (“BP”) 75% operated working interest in the five block deep water Pompano field in Mississippi Canyon, a 51% operated working interest in the adjacent Mississippi Canyon Block 29, a 50% non-operated working interest in the Mica field that ties back to the Pompano platform and a 75% interest in 23 deep water exploration leases located in the vicinity of the Pompano field. The following unaudited summary pro forma combined statement of operations data of Stone for the three and nine-month periods ended September 30, 2011 has been prepared to give effect to the acquisition of the deep water assets from BP as if it had occurred on January 1, 2010. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2010 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.


	Three Months Ended September 30, 2011 (unaudited)		Nine Months Ended September 30, 2011 (unaudited)
	(in millions, except per share amounts)
Revenues	$	238.7	$	750.0
Income from operations		93.1		298.0
Net income		58.9		184.5
Basic earnings per share	$	1.20	$	3.77
Diluted earnings per share	$	1.20	$	3.77

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, 2012 and December 31, 2011, 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 money market funds and fixed income 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 see Note 3 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in money market funds and fixed income securities, which are included within the Level 1 fair value hierarchy.

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at September 30, 2012:


	Fair Value Measurements at September 30, 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)
Fixed income securities	$	6.0		$	6.0	$	—		$	—
Hedging contracts		52.2			—		52.2			—

Total	$	58.2		$	6.0	$	52.2		$	—


	Fair Value Measurements at September 30, 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	($	3.3	)	$	—	($	3.3	)	$	—

Total	($	3.3	)	$	—	($	3.3	)	$	—

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2011:


	Fair Value Measurements at December 31, 2011
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)
Money market funds	$	5.6		$	5.6	$	—		$	—
Hedging contracts		47.7			—		47.7			—

Total	$	53.3		$	5.6	$	47.7		$	—


	Fair Value Measurements at December 31, 2011
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	($	11.9	)	$	—	($	11.9	)	$	—

Total	($	11.9	)	$	—	($	11.9	)	$	—

The fair value of cash and cash equivalents and our variable rate bank debt approximated book value at September 30, 2012 and December 31, 2011. As of September 30, 2012 and December 31, 2011, the fair value of our $375 million 8⁵/₈% Senior Notes due 2017 was approximately $403.1 million and $386.3 million, respectively. As of September 30, 2012 and December 31, 2011, the fair value of our $200 million 6³/₄% Senior Subordinated Notes due 2014 was approximately $200.8 million and $199.0 million, respectively. As of September 30, 2012, the fair value of the liability component of our 2017 Convertible Notes was approximately $247.9 million. The fair value of our outstanding notes was determined based upon quotes obtained from brokers, which represent Level 2 inputs.

We applied fair value concepts in determining the liability component of our 2017 Convertible Notes (see Note 4 – Long-Term Debt) at inception and at September 30, 2012. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

We applied fair value concepts in the recording of deep water assets acquired from APC (see Note 6 – Acquisitions). The fair value of proved and unevaluated oil and gas properties was estimated using a market approach. Significant inputs were market value comparisons for similar transactions within an appropriate time period. These inputs were considered Level 3 inputs. Asset retirement obligations were determined in accordance with applicable accounting standards.

Note 8 – 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 (“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 assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the Outer Continental Shelf (“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 $29.3 million. The franchise tax years 2010 and 2011 for Stone remain subject to examination, which potentially exposes us to additional estimated assessments of $1.7 million including accrued interest. We estimate the potential range of loss upon resolution of this matter to be between $0 and $31 million.

Note 9 – Guarantor Financial Statements

Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of our 2017 Convertible Notes, our 8⁵/₈% Senior Notes due 2017 and our 6³/₄% Senior Subordinated Notes due 2014. Our other subsidiary (the “Non-Guarantor Subsidiary”) did not provide a guarantee. Our non-guarantor subsidiary, Caillou Boca Gathering, LLC, was merged into Stone Offshore on September 6, 2012. The following presents unaudited condensed consolidating financial information as of September 30, 2012 and December 31, 2011 and for the three and nine-month periods ended September 30, 2012 and 2011 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiary and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

SEPTEMBER 30, 2012

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiary		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	155,089		$	21,097		$	—	$	—		$	176,186
Accounts receivable		45,692			289,989			—		(208,431	)		127,250
Fair value of hedging contracts		—			34,010			—		—			34,010
Current income tax receivable		24,066			—			—		—			24,066
Deferred taxes *		2,465			9,815			—		—			12,280
Inventory		4,223			283			—		—			4,506
Other current assets		3,246			—			—		—			3,246

Total current assets		234,781			355,194			—		(208,431	)		381,544
Oil and gas properties, full cost method:
Proved		890,616			6,148,834			—		—			7,039,450
Less: accumulated DD&A		(353,857	)		(5,073,811	)		—		—			(5,427,668	)

Net proved oil and gas properties		536,759			1,075,023			—		—			1,611,782
Unevaluated		287,645			166,994			—		—			454,639
Other property and equipment, net		13,399			—			—		—			13,399
Fair value of hedging contracts		—			18,155			—		—			18,155
Other assets, net		33,843			1,315			—		—			35,158
Investment in subsidiary		902,154			—			—		(902,154	)		—

Total assets	$	2,008,581		$	1,616,681		$	—	($	1,110,585	)	$	2,514,677

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	286,752		$	21,041		$	—	($	208,431	)	$	99,362
Undistributed oil and gas proceeds		22,822			1,455			—		—			24,277
Accrued interest		9,774			—			—		—			9,774
Fair value of hedging contracts		—			1,077			—		—			1,077
Asset retirement obligations		—			59,366			—		—			59,366
Other current liabilities		10,030			1,375			—		—			11,405

Total current liabilities		329,378			84,314			—		(208,431	)		205,261
Long-term debt		811,024			—			—		—			811,024
Deferred taxes *		20,373			277,727			—		—			298,100
Asset retirement obligations		7,515			343,508			—		—			351,023
Fair value of hedging contracts		—			2,266			—		—			2,266
Other long-term liabilities		14,132			6,712			—		—			20,844

Total liabilities		1,182,422			714,527			—		(208,431	)		1,688,518

Commitments and contingencies
Stockholders’ equity:
Common stock		484			—			—		—			484
Treasury stock		(860	)		—			—		—			(860	)
Additional paid-in capital		1,383,741			1,724,232			—		(1,724,232	)		1,383,741
Accumulated earnings (deficit)		(587,045	)		(851,917	)		—		851,917			(587,045	)
Accumulated other comprehensive income (loss)		29,839			29,839			—		(29,839	)		29,839

Total stockholders’ equity		826,159			902,154			—		(902,154	)		826,159

Total liabilities and stockholders’ equity	$	2,008,581		$	1,616,681		$	—	($	1,110,585	)	$	2,514,677

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

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2011

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	37,389		$	926		$	136		$	—		$	38,451
Accounts receivable		36,463			81,452			1,353			(1,129	)		118,139
Fair value of hedging contracts		—			25,177			—			—			25,177
Current income tax receivable		19,946			—			—			—			19,946
Deferred taxes *		8,269			17,803			—			—			26,072
Inventory		4,360			283			—			—			4,643
Other current assets		791			—			—			—			791

Total current assets		107,218			125,641			1,489			(1,129	)		233,219
Oil and gas properties, full cost method:
Proved		696,975			5,946,141			5,052			—			6,648,168
Less: accumulated DD&A		(309,421	)		(4,862,949	)		(2,359	)		—			(5,174,729	)

Net proved oil and gas properties		387,554			1,083,192			2,693			—			1,473,439
Unevaluated		246,269			155,340			—			—			401,609
Other property and equipment, net		11,172			—			—			—			11,172
Fair value of hedging contracts		—			22,543			—			—			22,543
Other assets, net		20,873			2,896			—			—			23,769
Investment in subsidiary		733,533			(273	)		—			(733,260	)		—

Total assets	$	1,506,619		$	1,389,339		$	4,182		($	734,389	)	$	2,165,751

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	78,170		$	25,866		$	39		($	1,129	)	$	102,946
Undistributed oil and gas proceeds		26,036			1,292			—			—			27,328
Accrued interest		14,059			—			—			—			14,059
Fair value of hedging contracts		—			11,122			—			—			11,122
Asset retirement obligations		—			62,676			—			—			62,676
Other current liabilities		22,974			5,396			—			—			28,370

Total current liabilities		141,239			106,352			39			(1,129	)		246,501
Long-term debt		620,000			—			—			—			620,000
Deferred taxes *		56,970			190,865			—			—			247,835
Asset retirement obligations		7,626			351,061			4,416			—			363,103
Fair value of hedging contracts		—			815			—			—			815
Other long-term liabilities		12,955			6,713			—			—			19,668

Total liabilities		838,790			655,806			4,455			(1,129	)		1,497,922

Commitments and contingencies
Stockholders’ equity:
Common stock		481			—			—			—			481
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,338,565			1,724,232			1,639			(1,725,871	)		1,338,565
Accumulated earnings (deficit)		(692,225	)		(1,012,567	)		(1,912	)		1,014,479			(692,225	)
Accumulated other comprehensive income (loss)		21,868			21,868			—			(21,868	)		21,868

Total stockholders’ equity		667,829			733,533			(273	)		(733,260	)		667,829

Total liabilities and stockholders’ equity	$	1,506,619		$	1,389,339		$	4,182		($	734,389	)	$	2,165,751

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

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2012

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			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
Other operational expenses		61			21			—			—			82
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
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) loss from investment in subsidiaries		(42,200	)		(24	)		—			42,224			—

Total other (income) expenses		(34,739	)		(353	)		—			42,224			7,132

Income (loss) 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 (loss)	$	23,659		$	42,200		$	24		($	42,224	)	$	23,659

Comprehensive income (loss)	($	9,507	)	$	42,200		$	24		($	42,224	)	($	9,507	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2011

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			Eliminations			Consolidated
Operating revenue:
Oil production	$	1,248		$	156,188		$	—		$	—		$	157,436
Gas production		6,772			35,999			—			—			42,771
Natural gas liquids production		—			9,060			—			—			9,060
Other operational income		1,050			94			101			—			1,245
Derivative income, net		—			4,082			—			—			4,082

Total operating revenue		9,070			205,423			101			—			214,594

Operating expenses:
Lease operating expenses		1,716			44,682			193			—			46,591
Transportation, processing and gathering expenses		—			2,763			—			—			2,763
Other operational expenses		622			32			—			—			654
Production taxes		422			2,070			—			—			2,492
Depreciation, depletion, amortization		5,615			58,630			217			—			64,462
Accretion expense		3			7,605			92			—			7,700
Salaries, general and administrative		7,193			(43	)		1			—			7,151
Incentive compensation expense		2,087			—			—			—			2,087

Total operating expenses		17,658			115,739			503			—			133,900

Income (loss) from operations		(8,588	)		89,684			(402	)		—			80,694

Other (income) expenses:
Interest expense		1,305			74			—			—			1,379
Interest income		(23	)		—			—			—			(23	)
Other income		(6	)		(366	)		—			—			(372	)
Other expense		308			—			—			—			308
(Income) loss from investment in subsidiaries		(60,498	)		401			—			60,097			—

Total other (income) expenses		(58,914	)		109			—			60,097			1,292

Income (loss) before taxes		50,326			89,575			(402	)		(60,097	)		79,402

Provision (benefit) for income taxes:
Current		(12,681	)		—			—			—			(12,681	)
Deferred		11,186			29,076			—			—			40,262

Total income taxes		(1,495	)		29,076			—			—			27,581

Net income (loss)	$	51,821		$	60,499		($	402	)	($	60,097	)	$	51,821

Comprehensive income (loss)	$	127,828		$	60,499		($	402	)	($	60,097	)	$	127,828

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2012

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			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
Other operational expenses		150			45			—			—			195
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

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

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2011

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			Eliminations			Consolidated
Operating revenue:
Oil production	$	2,766		$	482,022		$	—		$	—		$	484,788
Gas production		12,355			119,460			—			—			131,815
Natural gas liquids production		—			25,290			—			—			25,290
Other operational income		2,359			179			456			—			2,994
Derivative income, net		—			3,300			—			—			3,300

Total operating revenue		17,480			630,251			456			—			648,187

Operating expenses:
Lease operating expenses		2,462			127,831			193			—			130,486
Transportation, processing and gathering expenses		—			7,311			—			—			7,311
Other operational expenses		715			734			3			—			1,452
Production taxes		814			6,014			—			—			6,828
Depreciation, depletion, amortization		11,533			192,566			678			—			204,777
Accretion expense		11			22,849			274			—			23,134
Salaries, general and administrative		29,486			7			1			—			29,494
Incentive compensation expense		7,104			—			—			—			7,104

Total operating expenses		52,125			357,312			1,149			—			410,586

Income (loss) from operations		(34,645	)		272,939			(693	)		—			237,601

Other (income) expenses:
Interest expense		6,315			155			—			—			6,470
Interest income		(164	)		(6	)		—			—			(170	)
Other income		(19	)		(1,480	)		—			—			(1,499	)
Loss on early extinguishment of debt		607			—			—			—			607
Other expense		500			1			—			—			501
(Income) loss from investment in subsidiaries		(177,442	)		692			—			176,750			—

Total other (income) expenses		(170,203	)		(638	)		—			176,750			5,909

Income (loss) before taxes		135,558			273,577			(693	)		(176,750	)		231,692

Provision (benefit) for income taxes:
Current		(12,690	)		(2,353	)		—			—			(15,043	)
Deferred		(561	)		98,487			—			—			97,926

Total income taxes		(13,251	)		96,134			—			—			82,883

Net income (loss)	$	148,809		$	177,443		($	693	)	($	176,750	)	$	148,809

Comprehensive income (loss)	$	228,454		$	177,443		($	693	)	($	176,750	)	$	228,454

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2012

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			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
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

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2011

(In thousands of dollars)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiary			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	148,809		$	177,443		($	693	)	($	176,750	)	$	148,809
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		11,533			192,566			678			—			204,777
Accretion expense		11			22,849			274			—			23,134
Deferred income tax provision (benefit)		(561	)		98,487			—			—			97,926
Settlement of asset retirement obligations		—			(52,543	)		—			—			(52,543	)
Non-cash stock compensation expense		4,492			—			—			—			4,492
Excess tax benefits		(1,490	)		—			—			—			(1,490	)
Non-cash derivative income		—			(4,337	)		—			—			(4,337	)
Loss on early extinguishment of debt		607			—			—			—			607
Non-cash (income) loss from investment in subsidiaries		(175,962	)		(788	)		—			176,750			—
Non-cash interest expense		1,412			—			—			—			1,412
Other non-cash (income) expense		(1,362	)		—			—			—			(1,362	)
Change in current income taxes		(19,357	)		(2,353	)		—			—			(21,710	)
Change in intercompany receivables/payables		233,904			(233,577	)		(327	)		—			—
(Increase) decrease in accounts receivable		(16,878	)		(242	)		3			—			(17,117	)
(Increase) decrease in other current assets		(200	)		15			—			—			(185	)
Decrease in inventory		1,592			14			—			—			1,606
Increase (decrease) in accounts payable		2,709			(30	)		—			—			2,679
Increase in other current liabilities		1,124			2,480			—			—			3,604
Other		(1,889	)		—			—			—			(1,889	)

Net cash provided by (used in) operating activities		188,494			199,984			(65	)		—			388,413

Cash flows from investing activities:
Investment in oil and gas properties		(227,862	)		(202,845	)		(4	)		—			(430,711	)
Proceeds from sale of oil and gas properties, net of expenses		5,575			2,117			—			—			7,692
Investment in fixed and other assets		(1,788	)		—			—			—			(1,788	)

Net cash used in investing activities		(224,075	)		(200,728	)		(4	)		—			(424,807	)

Cash flows from financing activities:
Deferred financing costs		(4,017	)		—			—			—			(4,017	)
Excess tax benefits		1,490			—			—			—			1,490
Net payments for share based compensation		(2,581	)		—			—			—			(2,581	)

Net cash used in financing activities		(5,108	)		—			—			—			(5,108	)

Net change in cash and cash equivalents		(40,689	)		(744	)		(69	)		—			(41,502	)
Cash and cash equivalents, beginning of period		105,115			1,659			182			—			106,956

Cash and cash equivalents, end of period	$	64,426		$	915		$	113		$	—		$	65,454

Note 10 – Subsequent Events

On October 22, 2012, we commenced a public offering of $300 million in aggregate principal amount of Senior Notes due 2022. In connection with this offering, we entered into an amendment to our bank credit facility (see Note 4 – Long-Term Debt). On October 23, 2012, we priced the offering of the 2022 Notes, which will bear interest at a rate of 7.50% per annum and will be issued at a price equal to 98.277% of the principal amount thereof, resulting in a yield to maturity of 7.75%. We expect to close the sale of the 2022 Notes on November 8, 2012, subject to the satisfaction of customary closing conditions. On October 22, 2012, we also commenced a cash tender offer and consent solicitation with respect to any and all of the $200 million aggregate outstanding principal amount of our 2014 Notes.

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 and other publicly available documents include “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 2011 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.

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

•

any expected results or benefits associated with our acquisitions;

•

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;

•

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 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;

•

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 ceiling test write-downs 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;

•

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;

•

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

•

consequences of the Deepwater Horizon oil spill and resulting stringent regulatory requirements;

•

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

•

the other risks described in our 2011 Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q.

Should one or more of the risks or uncertainties described above, in our 2011 Annual Report on Form 10-K or in our Quarterly Reports on 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 Quarterly Report on Form 10-Q should be read in conjunction with the MD&A contained in our 2011 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 (“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 Policies

Our 2011 Annual Report on Form 10-K describes the accounting policies 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;

•

the 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 income taxes; and

•

contingencies.

This Quarterly Report on Form 10-Q should be read together with the discussion contained in our 2011 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 Quarterly Report on Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2011 Annual Report on Form 10-K regarding these other risk factors and in this report under Part II, Item 1A. “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 narrowed our insurance coverage to selected properties, increased our deductibles and are assuming more hurricane related risk in the environment of 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. See “Part II, Item 1. Legal Proceedings.”

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 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 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.

Liquidity and Capital Resources

At November 2, 2012, we had $379 million of availability under our bank credit facility and cash on hand of approximately $153 million. Our capital expenditure budget for 2012 has been set at $625 million, which excludes material acquisitions and capitalized salaries, general and administrative expenses and interest. We intend to finance our remaining capital expenditure budget primarily with cash on hand and cash flow from operations.

Cash Flow and Working Capital. Net cash provided by operating activities totaled $373.9 million during the nine months ended September 30, 2012 compared to $388.4 million in the comparable period in 2011. Based on our outlook of commodity prices and our estimated production, we expect to fund our remaining 2012 capital expenditures with cash on hand and cash flow provided by operating activities.

Net cash used in investing activities totaled $448.8 million and $424.8 million during the nine months ended September 30, 2012 and 2011, respectively, which primarily represents our investment in oil and natural gas properties.

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 our 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. Net cash used in financing activities totaled $5.1 million for the nine months ended September 30, 2011, which primarily represents $4.0 million of deferred financing costs associated with our bank credit facility and $2.6 million of net payments for share based compensation, slightly offset by $1.5 million of excess tax benefits related to share based compensation.

We had working capital at September 30, 2012 of $176.3 million. Included in working capital at September 30, 2012 is a portion of the proceeds received from the issuance of our 2017 Convertible Notes (see Senior Convertible Notes below).

Capital Expenditures. During the three months ended September 30, 2012, additions to oil and gas property costs of $130.8 million included $16.1 million of lease and property acquisition costs, $5.5 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $9.5 million of capitalized interest. During the nine months ended September 30, 2012, additions to oil and gas property costs of $444.3 million included $59.0 million of lease and property acquisition costs, $17.7 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $27.7 million of capitalized interest. These investments were financed with cash flow from operations and the net proceeds from the 2017 Convertible Notes.

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 $700 million facility. The bank credit facility matures on September 15, 2014. However, if the notes issued under our 2004 indenture are retired on or before April 15, 2014, the bank credit facility will mature on April 26, 2015. On October 22, 2012, our borrowing base under our bank credit facility was reaffirmed at $400 million. As of September 30 and November 2, 2012, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.0 million had been issued pursuant to the bank credit facility, leaving $379.0 million of availability under the facility. Our bank credit facility is guaranteed by our only subsidiary, Stone Offshore.

On October 22, 2012, we commenced a public offering of $300 million in aggregate principal amount of Senior Notes due 2022. On October 22, 2012, we entered into an amendment and obtained a consent from our lenders, which (1) provides that the borrowing base under our bank credit facility will not be reduced as a result of the issuance of the 2022 Notes; provided, however, that, if the 2022 Notes are issued, to the extent that the 2014 Notes in an aggregate principal amount equal to $200 million shall not have been repurchased, repaid, defeased or otherwise retired on or prior to December 31, 2012, the borrowing base will be reduced automatically on December 31, 2012 by an amount equal to 30% of the difference between $200 million and the aggregate principal amount of 2014 Notes so repurchased, repaid, defeased or otherwise retired, and (2) increases our basket for outstanding notes from $900 million in the aggregate to $1.25 billion on or prior to December 31, 2012, and to $1.1 billion at any time thereafter.

The borrowing base under our bank credit facility is redetermined by the lenders semi-annually, on May 1 and November 1, 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 the 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. 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, 2012.

7.50% Senior Notes due 2022. On October 22, 2012, we commenced a public offering of $300 million in aggregate principal amount of Senior Notes due 2022. We intend to use the net proceeds from the offering to fund our pending tender offer and consent solicitation for our 2014 Notes and for general corporate purposes. On October 23, 2012, we priced the offering of the 2022 Notes, which will bear interest at a rate of 7.50% per annum and will be issued at a price equal to 98.277% of the principal amount thereof, resulting in a yield to maturity of 7.75%. We expect to close the sale of the 2022 Notes on November 8, 2012, subject to the satisfaction of customary closing conditions.

6³/₄% Senior Subordinated Notes due 2014. On October 22, 2012, we commenced a cash tender offer and consent solicitation with respect to any and all of the $200 million aggregate outstanding principal amount of our 2014 Notes. Assuming full participation in the tender offer, the total cost of the redemption is estimated to be approximately $206.4 million. We expect the transaction will result in an after-tax charge to earnings of an estimated $1.5 million in the fourth quarter of 2012.

Senior Convertible Notes. On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of 1³/₄% Senior Convertible Notes due 2017 to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The 2017 Convertible Notes are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the sale of the 2017 Convertible Notes were approximately $291.1 million, after deducting fees and expenses. The 2017 Convertible Notes bear interest at a rate of 1.75% per year, payable on March 1 and September 1 of each year, beginning on September 1, 2012. The 2017 Convertible Notes mature on March 1, 2017, unless earlier converted or repurchased. We may not redeem the 2017 Convertible Notes at our option prior to the maturity date.

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 28, 2012, our closing share price was $25.12. 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 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 in respect of our common stock. These convertible note hedge transactions are expected to reduce the potential dilution upon future conversion of the 2017 Convertible Notes. In addition, we entered into separate warrant transactions at a higher strike price. The warrant transactions could separately have a dilutive effect to the extent that the market value per share of our common stock exceeds the applicable strike price of the warrants.

We applied a portion of the net proceeds of $291.1 million from the sale of the 2017 Convertible Notes and the proceeds from the warrant transactions of $40.1 million to fund the cost of the convertible note hedge transactions of $70.8 million. We also used a portion of the net proceeds to repay $70 million of outstanding borrowings under our bank credit facility.

Results of Operations

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


	Three Months Ended September 30,
	2012		2011		Variance			% Change
Production:
Oil (MBbls)		1,736		1,521		215			14	%
Natural gas (MMcf)		10,615		9,544		1,071			11	%
Natural gas liquids (MBbls)		341		149		192			129	%
Oil, natural gas and NGLs (MMcfe)		23,077		19,564		3,513			18	%
Revenue data (in thousands) (a):
Oil revenue	$	180,806	$	157,436	$	23,370			15	%
Natural gas revenue		34,003		42,771		(8,768	)		(21	%)
Natural gas liquids revenue		11,910		9,060		2,850			31	%

Total oil, natural gas and NGL revenue	$	226,719	$	209,267	$	17,452			8	%
Average prices (a):
Oil (per Bbl)	$	104.15	$	103.51	$	0.64			1	%
Natural gas (per Mcf)		3.20		4.48		(1.28	)		(29	%)
Natural gas liquids (per Bbl)		34.93		60.81		(25.88	)		(43	%)
Oil, natural gas and NGLs (per Mcfe)		9.82		10.70		(0.88	)		(8	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.64	$	2.38	$	0.26			11	%
Salaries, general and administrative expenses (b)		0.59		0.37		0.22			59	%
DD&A expense on oil and gas properties		3.83		3.26		0.57			17	%

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

(b)	Exclusive of incentive compensation expense.


	Nine Months Ended September 30,
	2012		2011		Variance			% Change
Production:
Oil (MBbls)		5,289		4,804		485			10	%
Natural gas (MMcf)		31,031		29,025		2,006			7	%
Natural gas liquids (MBbls)		794		429		365			85	%
Oil, natural gas and NGLs (MMcfe)		67,529		60,423		7,106			12	%
Revenue data (in thousands) (a):
Oil revenue	$	564,745	$	484,788	$	79,957			16	%
Natural gas revenue		91,006		131,815		(40,809	)		(31	%)
Natural gas liquids revenue		35,228		25,290		9,938			39	%

Total oil, natural gas and NGL revenue	$	690,979	$	641,893	$	49,086			8	%
Average prices (a):
Oil (per Bbl)	$	106.78	$	100.91	$	5.87			6	%
Natural gas (per Mcf)		2.93		4.54		(1.61	)		(35	%)
Natural gas liquids (per Bbl)		44.37		58.95		(14.58	)		(25	%)
Oil, natural gas and NGLs (per Mcfe)		10.23		10.62		(0.39	)		(4	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.33	$	2.16	$	0.17			8	%
Salaries, general and administrative expenses (b)		0.60		0.49		0.11			22	%
DD&A expense on oil and gas properties		3.83		3.34		0.49			15	%

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

(b)	Exclusive of incentive compensation expense.

Net Income. During the three months ended September 30, 2012, we reported net income totaling $23.7 million, or $0.48 per share, compared to net income for the three months ended September 30, 2011 of $51.8 million, or $1.06 per share. During the nine months ended September 30, 2012, we reported net income totaling $105.2 million, or $2.13 per share, compared to net income for the nine months ended September 30, 2011 of $148.8 million, or $3.04 per share. All per share amounts are on a diluted basis.

In the first quarter of 2012, we began reporting natural gas liquid (“NGL”) volumes and revenues separate from gas volumes. Historically, we reported “wet” gas volumes, which included entrained liquids. We will now report NGLs and “dry” gas (shrunk for removal of liquids) volumes. Prior period production volumes, revenues and prices have been reclassified to conform to the current presentation.

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

Production. During the three months ended September 30, 2012, total production volumes increased to 23.1 Bcfe compared to 19.6 Bcfe produced during the comparable 2011 period, representing an 18% increase. Oil production during the three months ended September 30, 2012 totaled approximately 1,736,000 Bbls compared to 1,521,000 Bbls produced during the three months ended September 30, 2011; natural gas production totaled 10.6 Bcf during the three months ended September 30, 2012 compared to 9.5 Bcf during the comparable 2011 period; and NGL production during the three months ended September 30, 2012 totaled approximately 341,000 Bbls compared to 149,000 Bbls produced during the comparable period of 2011.

During the nine months ended September 30, 2012, total production volumes increased to 67.5 Bcfe compared to 60.4 Bcfe produced during the comparable 2011 period, representing a 12% increase. Oil production during the nine months ended September 30, 2012 totaled approximately 5,289,000 Bbls compared to 4,804,000 Bbls produced during the nine months ended September 30, 2011; natural gas production totaled 31.0 Bcf during the nine months ended September 30, 2012 compared to 29.0 Bcf produced during the comparable period of 2011; and NGL production during the nine months ended September 30, 2012 totaled approximately 794,000 Bbls compared to 429,000 Bbls produced during the comparable period of 2011. The increase in NGL production resulted from our liquids rich Pompano and Appalachia gas streams coming on line. Production commenced from our deep water Pyrenees well at Garden Banks 293 during the first quarter of 2012. The nine months ended September 30, 2012 includes production from our Pompano field, which was acquired in late 2011.

Prices. Prices realized during the three months ended September 30, 2012 averaged $104.15 per Bbl of oil, $3.20 per Mcf of natural gas and $34.93 per Bbl of NGLs, or 8% lower, on an Mcfe basis, than average realized prices of $103.51 per Bbl of oil, $4.48 per Mcf of natural gas and $60.81 per Bbl of NGLs during the comparable 2011 period. Prices realized during the nine months ended September 30, 2012 averaged $106.78 per Bbl of oil, $2.93 per Mcf of natural gas and $44.37 per Bbl of NGLs compared to average realized prices of $100.91 per Bbl of oil, $4.54 per Mcf of natural gas and $58.95 per Bbl of NGLs during the comparable 2011 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 $0.55 per Mcf and increased our average realized oil price by $2.34 per Bbl during the three months ended September 30, 2012. During the three months ended September 30, 2011, our effective hedging transactions increased our average realized natural gas price by $0.48 per Mcf and decreased our average realized oil price by $2.16 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. During the nine months ended September 30, 2011, effective hedging transactions increased our average realized natural gas price by $0.45 per Mcf and decreased our average realized oil price by $5.43 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $226.7 million during the three months ended September 30, 2012, compared to $209.3 million during the comparable period of 2011. The increase is attributable to an 18% increase in production quantities on a gas equivalent basis, partially offset by an 8% decrease in average realized prices. Oil, natural gas and NGL revenue for the nine months ended September 30, 2012 was $691.0 million compared to $641.9 million during the comparable period of 2011. The increase is attributable to a 12% increase in production quantities on a gas equivalent basis.

Expenses. Lease operating expenses during the three months ended September 30, 2012 and 2011 totaled $61.0 million and $46.6 million, respectively. For the nine months ended September 30, 2012 and 2011, lease operating expenses totaled $157.0 million and $130.5 million, respectively. On a unit of production basis, lease operating expenses were $2.33 per Mcfe and $2.16 per Mcfe for the nine months ended September 30, 2012 and 2011, respectively. The increase in lease operating expenses in 2012 was primarily attributable to the impact of expenses at our Pompano field, which was acquired in December 2011, as well as seasonal major maintenance projects.

Transportation, processing and gathering expenses during the three months ended September 30, 2012 and 2011 totaled $6.8 million and $2.8 million, respectively. During the nine months ended September 30, 2012, transportation, processing and gathering expenses totaled $15.9 million compared to $7.3 million for the nine months ended September 30, 2011. The increase resulted from our liquids rich Pompano and Appalachia gas streams coming on line in early 2012.

Other operational expenses of $0.7 million during the three months ended September 30, 2011 was primarily related to a $0.3 million loss on the sale of non-dedicated tubular inventory and approximately $0.2 million of miscellaneous inventory charges. For the nine months ended September 30, 2011, other operational expenses of $1.5 million included $0.7 million for the settlement of litigation associated with an expensed operation in the first quarter of 2011, a $0.3 million loss on the sale of non-dedicated tubular inventory and $0.4 million of miscellaneous inventory charges.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three months ended September 30, 2012 totaled $88.4 million, or $3.83 per Mcfe, compared to $63.8 million, or $3.26 per Mcfe, during the comparable period of 2011. For the nine months ended September 30, 2012 and 2011, DD&A expense totaled $258.6 million, or $3.83 per Mcfe, and $201.9 million, or $3.34 per Mcfe, respectively. The increase in DD&A expense on a unit basis in 2012 is attributable to the unit cost of current year net reserve additions (including future development costs) exceeding the per unit amortizable base as of the beginning of the year.

Salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) for the three months ended September 30, 2012 were $13.7 million compared to $7.2 million for the three months ended September 30, 2011. For the nine months ended September 30, 2012 and 2011, SG&A expenses (exclusive of incentive compensation) totaled $40.5 million and $29.5 million, respectively. The increase is primarily the result of increased staffing and compensation adjustments (including stock based compensation) and a management fee of $1.0 million for transition services related to our Pompano acquisition.

For the three months ended September 30, 2012 and 2011, incentive compensation expense totaled $0.1 million and $2.1 million, respectively. For the nine months ended September 30, 2012 and 2011, incentive compensation expense totaled $3.9 million and $7.1 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, 2012 totaled $7.7 million, net of $9.5 million of capitalized interest, compared to interest expense of $1.4 million, net of $11.5 million of capitalized interest, during the comparable 2011 period. For the nine months ended September 30, 2012, interest expense totaled $21.1 million, net of $27.7 million of capitalized interest, compared to interest expense of $6.5 million, net of $32.0 million of capitalized interest, during the comparable 2011 period. The increase in interest expense is primarily the result of interest associated with the 2017 Convertible Notes issued on March 6, 2012.

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 herein 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 the Board of Directors. We believe our current hedging positions have hedged approximately 39% of our estimated 2012 production from estimated proved reserves, 47% of our estimated 2013 production from estimated proved reserves, 31% of our estimated 2014 production from estimated proved reserves and 11% of our estimated 2015 production from estimated proved reserves. See Item 1. Financial Statements – Note 3 – Derivative Instruments and Hedging Activities for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 2011 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

We had total debt outstanding of $811 million at September 30, 2012, all of which bears interest at fixed rates. The $811 million of fixed-rate debt is comprised of $236 million ($300 million face value) of 1³/₄% Senior Convertible Notes due 2017, $375 million of 8⁵/₈% Senior Notes due 2017 and $200 million of 6³/₄% Senior Subordinated Notes due 2014.

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) under the Exchange Act) as of the end of the period covered by this Quarterly Report on 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, 2012 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, 2012 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

Franchise Tax Action. On December 30, 2004, Stone was 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 in the 15^th Judicial District Court claiming additional franchise

taxes due for the taxable years ended December 31, 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, Stone was served with a petition (civil action number 2007-6754) claiming $1.5 million of additional franchise taxes due for the 2004 franchise tax year, plus accrued interest of $800,000 (calculated through November 30, 2007). Further, on January 7, 2009, Stone was served with a petition (civil action number 2008-7193) claiming additional franchise taxes due for the taxable years ended December 31, 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 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. Stone disagrees with these contentions and intends to vigorously defend itself against these claims. The franchise tax years 2010 and 2011 for Stone remain subject to examination.

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

There have been no material changes with respect to Stone’s risk factors previously reported in our 2011 Annual Report on Form 10-K.

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 to pay taxes associated with the employees’ vesting of restricted stock. The following table sets forth information regarding our repurchases or acquisitions of common stock during the three months ended September 30, 2012:


Period	Total Number of Shares (or Units) Purchased			Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet be Purchased Under the Plans or Programs
Share Repurchase Program:
July 2012		—			—		—
August 2012		—			—		—
September 2012		—			—		—

		—			—		—	$	92,928,632

Other:
July 2012		5,021	(a)	$	25.02		—
August 2012		—			—		—
September 2012		21,670	(a)		23.38		—

		26,691		$	23.69		—		N/A

Total		26,691		$	23.69		—

(a)	Amount includes shares withheld from employees and nonemployee directors upon the vesting of restricted stock in order to satisfy the required tax withholding obligations.

Item 6. Exhibits


3.1		Certificate of Incorporation of the Registrant, as amended on June 4, 1993, February 1, 2001 and February 19, 2002 (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)).

4.1		Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed December 17, 2004 (File No. 001-12074)).

4.2		First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)).

4.3		Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

4.4		Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

4.5		First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

4.6		Indenture related to the 1³/₄% Senior Convertible Notes due 2017, dated as of March 6, 2012, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A., as trustee (including form of 1³/₄% Senior Convertible Senior Note due 2017) (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.1		Amendment No. 1 and Consent dated as of February 28, 2012 to the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 5, 2012 (File No. 001-12074)).

10.2		Amendment No. 2 and Consent dated as of October 22, 2012 to the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 22, 2012 (File No. 001-12074)).

10.3		Base Bond Hedge Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).



10.4		Base Bond Hedge Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.5		Additional Bond Hedge Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.6		Additional Bond Hedge Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.7		Base Warrant Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.8		Base Warrant Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.9		Additional Warrant Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.10		Additional Warrant Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.11		Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.12		Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (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 Schema Document

**101.CAL		XBRL Calculation Linkbase Document

**101.DEF		XBRL Definition Linkbase Document

**101.LAB		XBRL Label Linkbase Document

**101.PRE		XBRL Presentation Linkbase Document

*	Filed or furnished herewith.

Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

#	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.

SIGNATURE

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, 2012	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)

EXHIBIT INDEX


Exhibit Number		Description

3.1		Certificate of Incorporation of the Registrant, as amended on June 4, 1993, February 1, 2001 and February 19, 2002 (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)).

4.1		Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed December 17, 2004 (File No. 001-12074)).

4.2		First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)).

4.3		Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

4.4		Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

4.5		First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

4.6		Indenture related to the 1³/₄% Senior Convertible Notes due 2017, dated as of March 6, 2012, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A., as trustee (including form of 1³/₄% Senior Convertible Senior Note due 2017) (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.1		Amendment No. 1 and Consent dated as of February 28, 2012 to the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 5, 2012 (File No. 001-12074)).

10.2		Amendment No. 2 and Consent dated as of October 22, 2012 to the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 22, 2012 (File No. 001-12074)).

10.3		Base Bond Hedge Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).



10.4		Base Bond Hedge Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.5		Additional Bond Hedge Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.6		Additional Bond Hedge Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.7		Base Warrant Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.8		Base Warrant Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.9		Additional Warrant Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.10		Additional Warrant Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.11		Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

10.12		Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (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 Schema Document

**101.CAL		XBRL Calculation Linkbase Document

**101.DEF		XBRL Definition Linkbase Document

**101.LAB		XBRL Label Linkbase Document

**101.PRE		XBRL 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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company