Stone Energy (SGY) 10-Q 2011 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

or

o 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 (State or Other Jurisdiction of Incorporation or Organization)	72-1235413 (I.R.S. Employer Identification No.)
625 E. Kaliste Saloom Road Lafayette, Louisiana (Address of Principal Executive Offices)	70508 (Zip Code)

Registrant’s Telephone Number, Including Area Code:(337) 237-0410

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. Yesþ Noo

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ Noo

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

Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

As of November 2, 2011, there were 48,982,571 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, 2011 and December 31, 2010		1
Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		2
Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		3
Notes to Condensed Consolidated Financial Statements		4
Report of Independent Registered Public Accounting Firm		19
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3. Quantitative and Qualitative Disclosures About Market Risk		27
Item 4. Controls and Procedures		27
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		29
Item 3. Defaults Upon Senior Securities	Not Applicable
Item 4. (Removed and Reserved)	Not Applicable
Item 5. Other Information	Not Applicable
Item 6. Exhibits		30
Signature		32
EX-15.1
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)

	September 30,			December 31,
	2011			2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	65,454		$	106,956
Restricted cash		—			5,500
Accounts receivable		113,547			88,529
Fair value of hedging contracts		56,767			12,955
Current income tax receivable		22,149			—
Deferred taxes		4,713			27,274
Inventory		4,802			6,465
Other current assets		933			768
Total current assets		268,365			248,447
Oil and gas properties, full cost method of accounting:
Proved		6,101,241			5,789,578
Less: accumulated depreciation, depletion and amortization		(5,009,076	)		(4,804,949	)
Net proved oil and gas properties		1,092,165			984,629
Unevaluated		511,574			413,180
Other property and equipment, net		11,191			10,722
Fair value of hedging contracts		50,171			—
Other assets, net		23,795			22,112
Total assets	$	1,957,261		$	1,679,090
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	90,659		$	103,208
Undistributed oil and gas proceeds		16,924			10,037
Accrued interest		9,358			14,062
Fair value of hedging contracts		951			32,144
Asset retirement obligations		55,068			42,300
Current income tax payable		—			239
Other current liabilities		17,496			16,075
Total current liabilities		190,456			218,065
Long-term debt		575,000			575,000
Deferred taxes		219,393			99,227
Asset retirement obligations		289,604			331,620
Fair value of hedging contracts		—			3,606
Other long-term liabilities		19,034			21,215
Total liabilities		1,293,487			1,248,733
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 48,076,951 and 47,764,505 shares, respectively		481			478
Treasury stock (16,582 shares, respectively, at cost)		(860	)		(860	)
Additional paid-in capital		1,336,460			1,331,500
Accumulated deficit		(737,748	)		(886,557	)
Accumulated other comprehensive income (loss)		65,441			(14,204	)
Total stockholders’ equity		663,774			430,357
Total liabilities and stockholders’ equity	$	1,957,261		$	1,679,090

The accompanying notes are an integral part of this statement.

1

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Operating revenue:
Oil production	$	157,436		$	97,688		$	484,788		$	301,412
Gas production		50,244			55,522			152,615			179,571
Other operational income		1,245			1,802			2,994			4,489
Derivative income, net		4,082			405			3,300			3,818
Total operating revenue		213,007			155,417			643,697			489,290
Operating expenses:
Lease operating expenses		47,767			36,882			133,307			112,429
Other operational expenses		654			3,003			1,452			5,450
Production taxes		2,492			1,517			6,828			4,761
Depreciation, depletion and amortization		64,462			60,482			204,777			184,900
Accretion expense		7,700			8,460			23,134			25,384
Salaries, general and administrative expenses		7,151			9,751			29,494			30,199
Incentive compensation expense		2,087			767			7,104			2,113
Total operating expenses		132,313			120,862			406,096			365,236
Income from operations		80,694			34,555			237,601			124,054
Other (income) expenses:
Interest expense		1,379			2,667			6,470			9,273
Interest income		(23	)		(51	)		(170	)		(1,110	)
Other income		(372	)		—			(1,499	)		(776	)
Loss on early extinguishment of debt		—			—			607			1,820
Other expense		308			57			501			546
Total other expenses		1,292			2,673			5,909			9,753
Net income before income taxes		79,402			31,882			231,692			114,301
Provision (benefit) for income taxes:
Current		(12,681	)		10,182			(15,043	)		4,918
Deferred		40,262			2,318			97,926			36,711
Total income taxes		27,581			12,500			82,883			41,629
Net income	$	51,821		$	19,382		$	148,809		$	72,672
Basic earnings per share	$	1.06		$	0.40		$	3.04		$	1.50
Diluted earnings per share	$	1.06		$	0.40		$	3.04		$	1.50
Average shares outstanding		48,029			47,713			47,963			47,659
Average shares outstanding assuming dilution.		48,071			47,727			48,006			47,681

The accompanying notes are an integral part of this statement.

2

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands of dollars)
(Unaudited)

	Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	148,809		$	72,672
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		204,777			184,900
Accretion expense		23,134			25,384
Deferred income tax provision		97,926			36,711
Settlement of asset retirement obligations		(52,543	)		(28,652	)
Non-cash stock compensation expense		4,492			4,023
Excess tax benefits		(1,490	)		(297	)
Non-cash derivative income		(4,337	)		(1,459	)
Loss on early extinguishment of debt		607			1,820
Other non-cash expense		50			741
Change in current income taxes		(21,710	)		(6,014	)
(Increase) decrease in accounts receivable		(17,117	)		39,569
Increase in other current assets		(185	)		(305	)
Decrease in inventory		1,606			1,778
Increase (decrease) in accounts payable		2,679			(1,265	)
Increase (decrease) in other current liabilities		3,604			(21,401	)
Other		(1,889	)		1,261
Net cash provided by operating activities		388,413			309,466
Cash flows from investing activities:
Investment in oil and gas properties		(430,711	)		(261,970	)
Proceeds from sale of oil and gas properties, net of expenses		7,692			31,635
Investment in fixed and other assets		(1,788	)		(1,722	)
Net cash used in investing activities		(424,807	)		(232,057	)
Cash flows from financing activities:
Repayments of bank borrowings		—			(125,000	)
Redemption of senior subordinated notes		—			(200,503	)
Proceeds from issuance of senior notes		—			275,000
Deferred financing costs		(4,017	)		(9,766	)
Excess tax benefits		1,490			297
Net payments for share based compensation		(2,581	)		(1,360	)
Net cash used in financing activities		(5,108	)		(61,332	)
Net increase (decrease) in cash and cash equivalents		(41,502	)		16,077
Cash and cash equivalents, beginning of period		106,956			69,293
Cash and cash equivalents, end of period	$	65,454		$	85,370

The accompanying notes are an integral part of this statement.

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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, 2011 and for the three and nine-month periods ended September 30, 2011 and 2010 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 at December 31, 2010 has been derived from the audited financial statements at that date. 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 Annual Report on Form 10-K for the year ended December 31, 2010. The results of operations for the three and nine-month periods ended September 30, 2011 are not necessarily indicative of future financial results. Certain 2010 amounts have been changed from amounts originally presented to correct a prior period immaterial error.

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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(in thousands, except per share data)
Income (numerator):
Basic:
Net income	$	51,821		$	19,382		$	148,809		$	72,672
Net income attributable to participating securities		(976	)		(315	)		(2,807	)		(1,181	)
Net income attributable to common stock — basic	$	50,845		$	19,067		$	146,002		$	71,491
Diluted:
Net income	$	51,821		$	19,382		$	148,809		$	72,672
Net income attributable to participating securities		(975	)		(314	)		(2,805	)		(1,180	)
Net income attributable to common stock — diluted	$	50,846		$	19,068		$	146,004		$	71,492
Weighted average shares (denominator):
Weighted average shares — basic		48,029			47,713			47,963			47,659
Diluted effect of stock options		42			14			43			22
Weighted average shares — diluted		48,071			47,727			48,006			47,681
Basic income per common share	$	1.06		$	0.40		$	3.04		$	1.50
Diluted income per common share	$	1.06		$	0.40		$	3.04		$	1.50

     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 376,000 and 422,000 shares for the three months ended September 30, 2011 and 2010, respectively. Stock options that were considered antidilutive totaled approximately 376,000 and 422,000 shares during the nine months ended September 30, 2011 and 2010, respectively.

     During each of the three-month periods ended September 30, 2011 and 2010, 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, 2011 and 2010, approximately 312,000 and 254,000 shares of common stock, respectively, were issued upon the vesting of restricted stock by employees and nonemployee directors.

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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 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 indicative 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 2011, 2012, 2013 and 2014 oil and natural gas production from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based upon 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 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 for 2011, 2012, 2013 and 2014 are with J.P. Morgan Chase Bank, N.A., 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, 2011 and December 31, 2010 were designated as effective cash flow hedges; however, during the nine-month periods ended September 30, 2011 and 2010, 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, 2011 and December 31, 2010.

Fair Value of Derivative Instruments at September 30, 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	$	56.8	Current liabilities: Fair value of hedging contracts		($1.0	)
	Long-term assets: Fair value of hedging contracts		50.2	Long-term liabilities: Fair value of hedging contracts		—
		$	107.0			($1.0	)

Fair Value of Derivative Instruments at December 31, 2010
(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	$	13.0	Current liabilities: Fair value of hedging contracts		($32.1	)
	Long-term assets: Fair value of hedging contracts		—	Long-term liabilities: Fair value of hedging contracts		(3.6	)
		$	13.0			($35.7	)

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     The following tables disclose the effect of derivative instruments in the statement of operations for the three and nine-month periods ended September 30, 2011 and 2010.

The Effect of Derivative Instruments on the Statement of Operations for the Three Months Ended September 30, 2011 and 2010
(in millions)

	Amount of Gain
Derivatives in	(Loss) Recognized					Gain Reclassified from					Gain Recognized in Income
Cash Flow Hedging	in OCI on					Accumulated OCI into Income					on Derivatives
Relationships	Derivatives (a)					(Effective Portion) (b)					(Ineffective Portion)
	2011		2010			Location	2011		2010		Location	2011		2010
						Operating revenue -
Commodity contracts	$	76.0		($6.5	)	oil/gas production	$	1.3	$	6.0	Derivative income, net	$	4.1	$	0.4
Total	$	76.0		($6.5	)		$	1.3	$	6.0		$	4.1	$	0.4

(a)	Net of related tax effect.
(b)	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. For the three months ended September 30, 2010, effective hedging contracts decreased oil revenue by $3.7 million and increased gas revenue by $9.7 million.

The Effect of Derivative Instruments on the Statement of Operations for the Nine Months Ended September 30, 2011 and 2010
(in millions)

	Amount of Gain
Derivatives in	(Loss) Recognized				Gain Reclassified from						Gain Recognized in Income
Cash Flow Hedging	in OCI on				Accumulated OCI into Income						on Derivatives
Relationships	Derivatives (a)				(Effective Portion) (b)						(Ineffective Portion)
	2011		2010		Location	2011			2010		Location	2011		2010
					Operating revenue -
Commodity contracts	$	79.6	$	21.6	oil/gas production		($13.1	)	$	8.2	Derivative income, net	$	3.3	$	3.8
Total	$	79.6	$	21.6			($13.1	)	$	8.2		$	3.3	$	3.8

(a)	Net of related tax effect.
(b)	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. For the nine months ended September 30, 2010, effective hedging contracts decreased oil revenue by $17.8 million and increased gas revenue by $26.0 million.

     At September 30, 2011, we had accumulated other comprehensive income of $65.4 million, net of tax, which related to the fair value of our swap contracts that were outstanding as of September 30, 2011. We believe that approximately $32.3 million of the accumulated other comprehensive income will be reclassified into earnings in the next twelve months.

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     The following table illustrates our hedging positions for calendar years 2011, 2012, 2013 and 2014 as of November 2, 2011:

	Fixed-Price Swaps
	NYMEX (except where noted)
	Natural Gas					Oil
	Daily Volume			Swap		Daily Volume			Swap
	(MMBtus/d)			Price		(Bbls/d)			Price
2011		10,000	(a)	$	4.565		1,000		$	70.05
2011		20,000			5.200		1,000			78.20
2011		10,000			6.830		1,000			80.20
2011							1,000			83.00
2011							1,000			83.05
2011							1,000	(b)		85.20
2011							1,000			85.25
2011							1,000			89.00
2011							1,000	(c)		97.75
2011							1,000	(c)		104.30
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							1,000			97.60
2012							1,000			100.00
2012							1,000			101.55
2012							1,000			104.25
2012							1,000	†		111.02
2013		10,000			5.270		1,000			97.15
2013		10,000			5.320		1,000			101.53
2013							1,000			103.00
2013							1,000			104.50
2013							1,000	†		107.30
2014							1,000	†		103.30

(a)	February — December
(b)	January — June
(c)	July — December
†	Brent oil contract

Note 4 — Long-Term Debt

     Long-term debt consisted of the following at:

	September 30,		December 31,
	2011			2010
	(in millions)
63/4% Senior Subordinated Notes due 2014	$	200.0	$	200.0
85/8% Senior Notes due 2017		375.0		375.0
Bank debt		—		—
Total long-term debt	$	575.0	$	575.0

     On September 30, 2011, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $61.1 million had been issued pursuant to the 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 new 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 new credit facility then matures on April 26, 2015. Our initial borrowing base under the new credit facility was set at $400 million. On October 31, 2011, the bank group reaffirmed the existing borrowing base at $400 million. As of November 2, 2011, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $61.1 million had been issued pursuant to the facility, leaving $338.9 million of availability under the facility. Our bank credit facility is guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

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     The borrowing base under our bank credit facility is redetermined by the lenders semi-annually, typically 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 our bank credit facility will bear interest at a rate based on the adjusted 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, 2011.

Note 5 — Comprehensive Income

     The following table illustrates the components of comprehensive income for the three and nine-month periods ended September 30, 2011 and 2010:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
	(in millions)
Net income	$	51.8	$	19.4		$	148.8	$	72.7
Other comprehensive income (loss), net of tax effect:
Adjustment for fair value accounting of derivatives		76.0		(6.5	)		79.6		21.6
Comprehensive income	$	127.8	$	12.9		$	228.4	$	94.3

Note 6 — Asset Retirement Obligations

     The change in our asset retirement obligations during the nine months ended September 30, 2011 is set forth below:

	Nine Months
	Ended
	September 30, 2011
	(in millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	373.9
Liabilities settled		(51.5	)
Divestment of properties		(0.8	)
Accretion expense		23.1
Asset retirement obligations as of the end of the period, including current portion	$	344.7

     In October 2010, we received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) indicating that certain identified wells and facilities operated by us would need to be retired on a timing schedule which was accelerated from the timing estimated in calculating liabilities for asset retirement obligations at December 31, 2009. In February 2011, we submitted an abandonment plan addressing the identified wells and facilities. The successor to the BOEMRE in this matter, the Bureau of Safety and Environmental Enforcement (“BSEE”), indicated it will issue a final order following its review of the plan. During 2010, we increased our asset retirement obligations in the amount of $54.4 million for the estimated impact of the accelerated timing of the retirement of these assets and other factors. The final order, expected to be issued by the BSEE, will ultimately determine the impact on our asset retirement obligations and could result in additional upward or downward revisions.

Note 7 — Fair Value Measurements

     U.S. Generally Accepted Accounting Principles establish a fair value hierarchy which 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.

8

     As of September 30, 2011 and December 31, 2010, 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. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy. For a more detailed description of our derivative instruments, seeNote 3 — Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in money market funds, 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, 2011:

	Fair Value Measurements at September 30, 2011
			Quoted Prices in
			Active Markets for		Significant Other		Significant
			Identical Assets		Observable Inputs		Unobservable Inputs
Assets	Total		(Level 1)		(Level 2)		(Level 3)
	(in millions)
Money market funds	$	5.3	$	5.3	$	—	$	—
Hedging contracts		106.9		—		106.9		—
Total	$	112.2	$	5.3	$	106.9	$	—

	Fair Value Measurements at September 30, 2011
				Quoted Prices
				in Active Markets
				for Identical		Significant Other			Significant
				Liabilities		Observable Inputs			Unobservable Inputs
Liabilities	Total			(Level 1)		(Level 2)			(Level 3)
	(in millions)
Hedging contracts		($1.0	)	$	—		($1.0	)	$	—
Total		($1.0	)	$	—		($1.0	)	$	—

     The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2010:

	Fair Value Measurements at December 31, 2010
			Quoted Prices in
			Active Markets for		Significant Other		Significant
			Identical Assets		Observable Inputs		Unobservable Inputs
Assets	Total		(Level 1)		(Level 2)		(Level 3)
	(in millions)
Money market funds	$	7.3	$	7.3	$	—	$	—
Hedging contracts		13.0		—		13.0		—
Total	$	20.3	$	7.3	$	13.0	$	—

	Fair Value Measurements at December 31, 2010
				Quoted Prices
				in Active Markets
				for Identical		Significant Other			Significant
				Liabilities		Observable Inputs			Unobservable Inputs
Liabilities	Total			(Level 1)		(Level 2)			(Level 3)
	(in millions)
Hedging contracts		($35.7	)	$	—		($35.7	)	$	—
Total		($35.7	)	$	—		($35.7	)	$	—

     The fair value of cash and cash equivalents approximated book value at September 30, 2011 and December 31, 2010. As of September 30, 2011 and December 31, 2010, the fair value of our $375 million 8⁵/8% Senior Notes due 2017 was

9

approximately $363.8 million and $380.6 million, respectively. As of September 30, 2011 and December 31, 2010, the fair value of our $200 million 6³/4% Senior Subordinated Notes due 2014 was approximately $196.0 million and $197.0 million, respectively. The fair value of our outstanding notes was determined based upon quotes obtained from brokers.

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 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 have received preliminary assessments from the LDR for additional franchise taxes 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 Outer Continental Shelf, 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. Total asserted claims plus estimated accrued interest amount to approximately $29.7 million. The franchise tax year 2010 for Stone remains subject to examination, which potentially exposes us to additional estimated assessments of $0.8 million including accrued interest.

     Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet,et al., filed civil action No. 110741 in the 17^th Judicial District Court, Lafourche Parish, Louisiana, against Stone. Plaintiffs have since filed three supplemental petitions, including a third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs alleged that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs. The Company disagreed with plaintiffs’ contentions. In October 2011, the parties agreed to a settlement of all claims asserted in this action, and we anticipate that the settlement will be effected not later than January 2012. The settlement was accrued in the current period financial statements, which did not have a material impact on our financial position or results of operations.

Note 9 — Subsequent Event

     On October 28, 2011 we entered into a definitive agreement to sell our interest in one of our offshore Gulf of Mexico fields to an unrelated third party for approximately $80 million. The sale will be accounted for as an adjustment to our net full cost pool with no gain or loss recognized since the adjustment is not expected to significantly alter the relationship between capitalized costs and proved reserves.

10

Note 10 — Guarantor Financial Statements

     Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of our 6³/4% Senior Subordinated Notes due 2014 and our 8⁵/8% Senior Notes due 2017. Our remaining subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents condensed consolidating financial information as of September 30, 2011 and December 31, 2010 and for the three and nine-month periods ended September 30, 2011 and 2010 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
SEPTEMBER 30, 2011
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	64,426		$	915		$	113		$	—		$	65,454
Accounts receivable		78,421			69,702			1,226			(35,802	)		113,547
Fair value of hedging contracts		—			56,767			—			—			56,767
Current income tax receivable		19,796			2,353			—			—			22,149
Deferred taxes *		4,684			29			—			—			4,713
Inventory		4,519			283			—			—			4,802
Other current assets		933			—			—			—			933
Total current assets		172,779			130,049			1,339			(35,802	)		268,365
Oil and gas properties, full cost method:
Proved, net		239,458			849,496			3,211			—			1,092,165
Unevaluated		305,945			205,629			—			—			511,574
Other property and equipment, net		11,191			—			—			—			11,191
Fair value of hedging contracts		—			50,171			—			—			50,171
Other assets, net		23,795			—			—			—			23,795
Investment in subsidiary		668,677			2,347			—			(671,024	)		—
Total assets	$	1,421,845		$	1,237,692		$	4,550			($706,826	)	$	1,957,261
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	75,576		$	50,885		$	—			($35,802	)	$	90,659
Undistributed oil and gas proceeds		15,609			1,315			—			—			16,924
Accrued interest		9,358			—			—			—			9,358
Fair value of hedging contracts		—			951			—			—			951
Asset retirement obligations		—			55,068			—			—			55,068
Other current liabilities		15,786			1,710			—			—			17,496
Total current liabilities		116,329			109,929			—			(35,802	)		190,456
Long-term debt		575,000			—			—			—			575,000
Deferred taxes *		54,226			165,167			—			—			219,393
Asset retirement obligations		194			284,721			4,689			—			289,604
Other long-term liabilities		12,322			6,712			—			—			19,034
Total liabilities		758,071			566,529			4,689			(35,802	)		1,293,487
Commitments and contingencies
Stockholders’ equity:
Common stock		481			—			—			—			481
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,336,460			1,673,597			1,639			(1,675,236	)		1,336,460
Accumulated earnings (deficit)		(737,748	)		(1,067,875	)		(1,778	)		1,069,653			(737,748	)
Accumulated other comprehensive income (loss).		65,441			65,441			—			(65,441	)		65,441
Total stockholders’ equity		663,774			671,163			(139	)		(671,024	)		663,774
Total liabilities and stockholders’ equity	$	1,421,845		$	1,237,692		$	4,550			($706,826	)	$	1,957,261

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

11

CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
DECEMBER 31, 2010
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	105,115		$	1,659		$	182		$	—		$	106,956
Restricted cash		5,500			—			—			—			5,500
Accounts receivable		26,760			61,560			902			(693	)		88,529
Fair value of hedging contracts		12,955			—			—			—			12,955
Deferred taxes *		27,274			—			—			—			27,274
Inventory		6,168			297			—			—			6,465
Other current assets		753			15			—			—			768
Total current assets		184,525			63,531			1,084			(693	)		248,447
Oil and gas properties, full cost method:
Proved, net		260,434			720,309			3,886			—			984,629
Unevaluated		337,725			75,455			—			—			413,180
Other property and equipment, net		10,722			—			—			—			10,722
Other assets, net		22,112			—			—			—			22,112
Investment in subsidiary		427,273			1,561			—			(428,834	)		—
Total assets	$	1,242,791		$	860,856		$	4,970			($429,527	)	$	1,679,090
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	60,019		$	43,881		$	—			($692	)	$	103,208
Undistributed oil and gas proceeds		9,491			546			—			—			10,037
Accrued interest		14,062			—			—			—			14,062
Fair value of hedging contracts		32,144			—			—			—			32,144
Asset retirement obligations		—			42,300			—			—			42,300
Current income tax payable		239			—			—			—			239
Other current liabilities		16,075			—			—			—			16,075
Total current liabilities		132,030			86,727			—			(692	)		218,065
Long-term debt		575,000			—			—			—			575,000
Deferred taxes *		(41,804	)		141,031			—			—			99,227
Asset retirement obligations		129,100			198,105			4,415			—			331,620
Fair value of hedging contracts		3,606			—			—			—			3,606
Other long-term liabilities		14,502			6,713			—			—			21,215
Total liabilities		812,434			432,576			4,415			(692	)		1,248,733
Commitments and contingencies
Stockholders’ equity:
Common stock		478			—			—			—			478
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,331,500			1,673,598			1,640			(1,675,238	)		1,331,500
Accumulated earnings (deficit)		(886,557	)		(1,245,318	)		(1,085	)		1,246,403			(886,557	)
Accumulated other comprehensive loss		(14,204	)		—			—			—			(14,204	)
Total stockholders’ equity		430,357			428,280			555			(428,835	)		430,357
Total liabilities and stockholders’ equity	$	1,242,791		$	860,856		$	4,970			($429,527	)	$	1,679,090

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

12

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	1,248		$	156,188		$	—		$	—		$	157,436
Gas production		6,772			43,472			—			—			50,244
Other operational income		1,050			94			101			—			1,245
Derivative income, net		—			4,082			—			—			4,082
Total operating revenue		9,070			203,836			101			—			213,007
Operating expenses:
Lease operating expenses		1,716			45,858			193			—			47,767
Other operational expense		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			114,152			503			—			132,313
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) expense, net		302			(366	)		—			—			(64	)
(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

13

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	16,653		$	81,035		$	—		$	—		$	97,688
Gas production		14,742			40,780			—			—			55,522
Other operational income		1,509			—			293			—			1,802
Derivative income, net		405			—			—			—			405
Total operating revenue		33,309			121,815			293			—			155,417
Operating expenses:
Lease operating expenses		19,865			17,017			—			—			36,882
Other operational expense		698			2,305			—			—			3,003
Production taxes		1,172			345			—			—			1,517
Depreciation, depletion, amortization		10,824			49,418			240			—			60,482
Accretion expense		3,624			4,725			111			—			8,460
Salaries, general and administrative		9,742			8			1			—			9,751
Incentive compensation expense		767			—			—			—			767
Total operating expenses		46,692			73,818			352			—			120,862
Income (loss) from operations		(13,383	)		47,997			(59	)		—			34,555
Other (income) expenses:
Interest expense		2,654			13			—			—			2,667
Interest income		(49	)		(2	)		—			—			(51	)
Other (income) expense, net		73			(16	)		—			—			57
(Income) loss from investment in subsidiaries		(29,671	)		59			—			29,612			—
Total other (income) expenses		(26,993	)		54			—			29,612			2,673
Income (loss) before taxes		13,610			47,943			(59	)		(29,612	)		31,882
Provision (benefit) for income taxes:
Current		10,182			—			—			—			10,182
Deferred		(15,954	)		18,272			—			—			2,318
Total income taxes		(5,772	)		18,272			—			—			12,500
Net income (loss)	$	19,382		$	29,671			($59	)		($29,612	)	$	19,382

14

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	2,766		$	482,022		$	—		$	—		$	484,788
Gas production		12,355			140,260			—			—			152,615
Other operational income		2,359			179			456			—			2,994
Derivative income, net		—			3,300			—			—			3,300
Total operating revenue		17,480			625,761			456			—			643,697
Operating expenses:
Lease operating expenses		2,462			130,652			193			—			133,307
Other operational expense		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			352,822			1,149			—			406,096
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) expense, net		481			(1,479	)		—			—			(998	)
Loss on early extinguishment of debt		607			—			—			—			607
(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

15

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	41,262		$	260,150		$	—		$	—		$	301,412
Gas production		44,166			135,405			—			—			179,571
Other operational income		3,696			(30	)		823			—			4,489
Derivative income, net		3,818			—			—			—			3,818
Total operating revenue		92,942			395,525			823			—			489,290
Operating expenses:
Lease operating expenses		37,061			75,368			—			—			112,429
Other operational expense		1,973			3,477			—			—			5,450
Production taxes		3,481			1,280			—			—			4,761
Depreciation, depletion, amortization		31,650			152,467			783			—			184,900
Accretion expense		10,878			14,174			332			—			25,384
Salaries, general and administrative		30,184			14			1			—			30,199
Incentive compensation expense		2,113			—			—			—			2,113
Total operating expenses		117,340			246,780			1,116			—			365,236
Income (loss) from operations		(24,398	)		148,745			(293	)		—			124,054
Other (income) expenses:
Interest expense		9,283			(10	)		—			—			9,273
Interest income		(1,106	)		(4	)		—			—			(1,110	)
Other (income) expense, net		442			(688	)		16			—			(230	)
Loss on early extinguishment of debt		1,820			—			—			—			1,820
(Income) loss from investment in subsidiaries		(95,536	)		309			—			95,227			—
Total other (income) expenses		(85,097	)		(393	)		16			95,227			9,753
Income (loss) before taxes		60,699			149,138			(309	)		(95,227	)		114,301
Provision (benefit) for income taxes:
Current		5,006			(88	)		—			—			4,918
Deferred		(16,979	)		53,690			—			—			36,711
Total income taxes		(11,973	)		53,602			—			—			41,629
Net income (loss)	$	72,672		$	95,536			($309	)		($95,227	)	$	72,672

16

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			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			—
Other non-cash expense		50			—			—			—			50
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 decrease 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

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	72,672		$	95,536			($309	)		($95,227	)	$	72,672
Adjustments to reconcile net income (loss) to net cash provided by operating activities:											—
Depreciation, depletion and amortization		31,650			152,467			783			—			184,900
Accretion expense		10,878			14,174			332			—			25,384
Deferred income tax provision (benefit)		(16,979	)		53,690			—			—			36,711
Settlement of asset retirement obligations		(5,012	)		(23,640	)		—			—			(28,652	)
Non-cash stock compensation expense		4,023			—			—			—			4,023
Excess tax benefits		(297	)		—			—			—			(297	)
Non-cash derivative income		(1,459	)		—			—			—			(1,459	)
Loss on early extinguishment of debt		1,820			—			—			—			1,820
Non-cash (income) loss from investment in subsidiaries		(95,536	)		309			—			95,227			—
Other non-cash expenses		741			—			—			—			741
Change in current income taxes		(5,926	)		(88	)		—			—			(6,014	)
(Increase) decrease in accounts receivable		231,945			(191,343	)		(1,033	)		—			39,569
(Increase) decrease in other current assets		(361	)		56			—			—			(305	)
Decrease in inventory		1,503			275			—			—			1,778
Increase (decrease) in accounts payable		(959	)		(306	)		—			—			(1,265	)
Decrease in other current liabilities		(21,171	)		(230	)		—			—			(21,401	)
Other		561			700			—			—			1,261
Net cash provided by (used in) operating activities		208,093			101,600			(227	)		—			309,466
Cash flows from investing activities:
Investment in oil and gas properties		(157,192	)		(104,687	)		(91	)		—			(261,970	)
Proceeds from sale of oil and gas properties, net of expenses		30,955			680			—			—			31,635
Investment in fixed and other assets		(1,722	)		—			—			—			(1,722	)
Net cash used in investing activities		(127,959	)		(104,007	)		(91	)		—			(232,057	)
Cash flows from financing activities:
Repayment of bank borrowings		(125,000	)		—			—			—			(125,000	)
Redemption of senior subordinated notes		(200,503	)		—			—			—			(200,503	)
Proceeds from issuance of senior notes		275,000			—			—			—			275,000
Deferred financing costs		(9,766	)		—			—			—			(9,766	)
Excess tax benefits		297			—			—			—			297
Net payments for share based compensation		(1,360	)		—			—			—			(1,360	)
Net cash used in financing activities		(61,332	)		—			—			—			(61,332	)
Net increase (decrease) in cash and cash equivalents		18,802			(2,407	)		(318	)		—			16,077
Cash and cash equivalents, beginning of period		64,830			3,963			500			—			69,293
Cash and cash equivalents, end of period	$	83,632		$	1,556		$	182		$	—		$	85,370

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:

We have reviewed the condensed consolidated balance sheet of Stone Energy Corporation as of September 30, 2011, and the related condensed consolidated statement of operations for the three and nine-month periods ended September 30, 2011 and 2010, and the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2011 and 2010. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Stone Energy Corporation as of December 31, 2010, and the related consolidated statements of operations, cash flows, changes in stockholders’ equity and comprehensive income for the year then ended (not presented herein) and in our report dated March 3, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2010, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Ernst & Young LLP

New Orleans, Louisiana
November 7, 2011

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

          The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 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 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;

• 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 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 Annual Report on Form 10-K for the year ended December 31, 2010, 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

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statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

          Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our Annual Report on Form 10-K for the year ended December 31, 2010. Certain 2010 amounts have been changed from amounts originally presented to correct a prior period immaterial error. All period to period comparisons are based upon corrected amounts.

Overview

          We are an independent oil and gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties located primarily in the Gulf of Mexico (“GOM”). 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. More recently, we have made strategic investments in the deep water and deep shelf GOM and in the Gulf Coast onshore, which we have targeted as important exploration areas. We are also active in the Appalachian region, where we have established a significant acreage position and have development operations in the Marcellus Shale. We have also targeted several exploratory oil projects in the Rocky Mountain region. Throughout this document, reference to our “Gulf Coast Basin” properties includes our Gulf Coast onshore, shelf, deep shelf and deep water properties.

Critical Accounting Policies

          Our 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 reserves 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 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 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

          Deepwater Horizon Explosion and Oil Spill- The April 2010 explosion and sinking of the Deepwater Horizon drilling rig and resulting oil spill has created uncertainties about the impact on our future operations in the GOM. Increased regulation in a number of areas could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of our unevaluated properties, a substantial portion of which is in the deep water of the GOM. As of September 30, 2011, we have substantial investments in unevaluated oil and gas properties that relate to offshore leases, the majority of which are in the deep water GOM. If the fair value of these investments were to fall below the recorded amounts, the excess would be transferred to evaluated oil and gas properties thereby affecting the computation of amounts for depreciation, depletion and amortization and potentially our ceiling test computation. As of September 30, 2011, the computation of our ceiling test indicated a cushion of approximately $549.6 million.

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          Asset Retirement Obligations— In October 2010, we received notification from BOEMRE indicating that certain identified wells and facilities operated by us would need to be retired on a timing schedule which was accelerated from the timing estimated in calculating liabilities for asset retirement obligations at December 31, 2009. In February 2011, we submitted an abandonment plan addressing the identified wells and facilities. The successor to BOEMRE in this matter, the BSEE, indicated it will issue a final order following its review of the plan. During 2010, we increased our asset retirement obligations in the amount of $54.4 million for the estimated impact of the accelerated timing of the retirement of these assets and other factors. The final order, expected to be issued by the BSEE, will ultimately determine the impact on our asset retirement obligations and could result in additional upward or downward revisions.

          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 is becoming more difficult to obtain. We have narrowed our insurance coverage to selected properties, increased our deductibles and are shouldering 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 Outer Continental Shelf (“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.”

Liquidity and Capital Resources

          At November 2, 2011, we had $338.9 million of availability under our bank credit facility and cash on hand of approximately $69.4 million. In May 2011, our capital expenditure budget for 2011 was increased from $425 million up to $500 million due to a projected increase in production, oil prices and estimated cash flow, combined with an attractive inventory of capital projects. Our capital expenditure budget excludes material acquisitions and capitalized salaries, general and administrative expenses and interest. We intend to finance our capital expenditure budget primarily with cash flow from operations and borrowings under our bank credit facility if necessary. If we do not have sufficient cash flow from operations or availability under our bank credit facility, we may be forced to reduce our capital expenditures. To the extent that 2011 cash flow from operations exceeds our estimated 2011 capital expenditures, we may expand our capital budget or invest in money markets.

          Although we do not budget material acquisitions, we are continually evaluating opportunities that fit our specific acquisition profile. To the extent any possible transaction would exceed our current sources of capital, we would consider accessing the public markets or monetizing other assets as a source of financing. On October 28, 2011, we entered into a definitive agreement to sell our interest in one of our offshore Gulf of Mexico fields to an unrelated third party for approximately $80 million. We expect to close on this transaction in the fourth quarter of 2011. We intend to utilize the provisions of Internal Revenue Code section 1031 to minimize the potential current tax impacts of this transaction. This will entail acquiring like-kind replacement property within 180 days of the closing on the sold property.

          There is a significant amount of uncertainty regarding our industry resulting from the explosion and sinking of the Deepwater Horizon oil rig in the Gulf of Mexico and resulting oil spill. Several bills were introduced before Congress in the months following the Deepwater Horizon incident which would, if adopted as originally proposed, have required us to demonstrate our capabilities for greater financial responsibility in the event of spills. In addition, we are subject to an annual evaluation by the Bureau of Ocean Energy Management, a successor to BOEMRE, for a continuation of our current exemption from supplemental bonding on plugging and abandoning obligations. It is possible that future legislation or agency action could have an adverse impact on our liquidity in the event we are required to post additional bonds or letters of credit.

          Cash Flow and Working Capital.Net cash flow provided by operating activities totaled $388.4 million during the nine months ended September 30, 2011 compared to $309.5 million in the comparable period in 2010. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2011 capital expenditures with cash flow provided by operating activities and borrowings under our bank credit facility.

          Net cash flow used in investing activities totaled $424.8 million and $232.1 million during the nine months ended September 30, 2011 and 2010, respectively, which primarily represents our investment in oil and natural gas properties, offset by proceeds from the sale of oil and natural gas properties.

          Net cash flow 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 new 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. Net cash flow used in financing activities totaled $61.3 million for the nine months ended September 30, 2010, which primarily represents repayments of borrowings under our bank credit facility of $125.0 million, the redemption of our 8¹/4% Senior

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Subordinated Notes due 2011 of $200.5 million, net of proceeds from the public offering of our 8⁵/8% Senior Notes due 2017 of approximately $275 million less $9.8 million of deferred financing costs.

          We had working capital at September 30, 2011 of $77.9 million.

          Capital Expenditures.During the three months ended September 30, 2011, additions to oil and gas property costs of $158.2 million included $12.2 million of lease and property acquisition costs, $5.0 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $11.5 million of capitalized interest. During the nine months ended September 30, 2011, additions to oil and gas property costs of $410.1 million included $46.9 million of lease and property acquisition costs, $17.1 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $32.0 million of capitalized interest. These investments were financed by cash flow from operations.

          Bank Credit Facility.On September 30, 2011, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $61.1 million had been issued pursuant to the 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 new 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 new credit facility then matures on April 26, 2015. Our initial borrowing base under the new credit facility was set at $400 million. On October 31, 2011, the bank group reaffirmed the existing borrowing base at $400 million. As of November 2, 2011, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $61.1 million had been issued pursuant to the facility, leaving $338.9 million of availability under the facility. Our bank credit facility is guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

          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 credit facility will bear interest at a rate based on the adjusted 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, 2011.

          Share Repurchase Program.On September 24, 2007, our Board of Directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. Through September 30, 2011, 300,000 shares had been repurchased under this program at a total cost of approximately $7.1 million, or an average price of $23.57 per share. No shares were repurchased during the nine months ended September 30, 2011.

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Results of Operations

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

	Three Months Ended
	September 30,
	2011		2010		Variance			% Change
Production:
Oil (MBbls)		1,521		1,347		174			13	%
Natural gas (MMcf)		9,713		10,130		(417	)		(4	%)
Oil and natural gas (MMcfe)		18,839		18,212		627			3	%
Revenue data (in thousands) (a):
Oil revenue	$	157,436	$	97,688	$	59,748			61	%
Natural gas revenue		50,244		55,522		(5,278	)		(10	%)
Total oil and natural gas revenue	$	207,680	$	153,210	$	54,470			36	%
Average prices (a):
Oil (per Bbl)	$	103.51	$	72.52	$	30.99			43	%
Natural gas (per Mcf)		5.17		5.48		(0.31	)		(6	%)
Oil and natural gas (per Mcfe)		11.02		8.41		2.61			31	%
Expenses (per Mcfe):
Lease operating expenses	$	2.54	$	2.03	$	0.51			25	%
Salaries, general and administrative expenses (b)		0.38		0.54		(0.16	)		(30	%)
DD&A expense on oil and gas properties		3.38		3.24		0.14			4	%

(a)	Includes the cash settlement of effective hedging contracts.
(b)	Exclusive of incentive compensation expense.

	Nine Months Ended
	September 30,
	2011		2010		Variance			% Change
Production:
Oil (MBbls)		4,804		4,199		605			14	%
Natural gas (MMcf)		29,907		31,874		(1,967	)		(6	%)
Oil and natural gas (MMcfe)		58,731		57,068		1,663			3	%
Revenue data (in thousands) (a):
Oil revenue	$	484,788	$	301,412	$	183,376			61	%
Natural gas revenue		152,615		179,571		(26,956	)		(15	%)
Total oil and natural gas revenue	$	637,403	$	480,983	$	156,420			33	%
Average prices (a):
Oil (per Bbl)	$	100.91	$	71.78	$	29.13			41	%
Natural gas (per Mcf)		5.10		5.63		(0.53	)		(9	%)
Oil and natural gas (per Mcfe)		10.85		8.43		2.42			29	%
Expenses (per Mcfe):
Lease operating expenses	$	2.27	$	1.97	$	0.30			15	%
Salaries, general and administrative expenses (b)		0.50		0.53		(0.03	)		(6	%)
DD&A expense on oil and gas properties		3.44		3.16		0.28			9	%

(a)	Includes the cash settlement of effective hedging contracts.
(b)	Exclusive of incentive compensation expense.

          During the three months ended September 30, 2011, we reported net income totaling $51.8 million, or $1.06 per share, compared to net income for the three months ended September 30, 2010 of $19.4 million, or $0.40 per share. During the nine months ended September 30, 2011, we reported net income totaling $148.8 million, or $3.04 per share, compared to net income for the nine months ended September 30, 2010 of $72.7 million, or $1.50 per share. All per share amounts are on a diluted basis.

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

          Production.During the three months ended September 30, 2011, total production volumes increased to 18.8 Bcfe compared to 18.2 Bcfe produced during the comparable 2010 period. Oil production during the three months ended September 30, 2011 totaled approximately 1,521,000 barrels compared to 1,347,000 barrels produced during the three months ended September 30, 2010, while natural gas production totaled 9.7 Bcf during the three months ended September 30, 2011 compared to

24

10.1 Bcf produced during the comparable period of 2010. Production for the three months ended September 30, 2011 was impacted by GOM shut-ins from Tropical Storm Lee, Appalachia shut-ins from Hurricane Irene and third party pipeline downtime in the GOM. During the nine months ended September 30, 2011, total production volumes increased to 58.7 Bcfe compared to 57.1 Bcfe produced during the comparable 2010 period. Oil production during the nine months ended September 30, 2011 totaled approximately 4,804,000 barrels compared to 4,199,000 barrels produced during the nine months ended September 30, 2010, while natural gas production totaled 29.9 Bcf during the nine months ended September 30, 2011 compared to 31.9 Bcf produced during the comparable period of 2010. The increase in oil production volumes was primarily due to increases in production at our Mississippi Canyon Block 109 and Ship Shoal Block 113 fields where we have development programs ongoing. The decrease in gas production volumes was primarily due to natural production declines.

          Prices. Prices realized during the three months ended September 30, 2011 averaged $103.51 per Bbl of oil and $5.17 per Mcf of natural gas, or 31% higher, on an Mcfe basis, than average realized prices of $72.52 per Bbl of oil and $5.48 per Mcf of natural gas during the comparable 2010 period. Prices realized during the nine months ended September 30, 2011 averaged $100.91 per Bbl of oil and $5.10 per Mcf of natural gas, or 29% higher, on an Mcfe basis, than average realized prices of $71.78 per Bbl of oil and $5.63 per Mcf of natural gas during the comparable 2010 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 $0.47 per Mcf and decreased our average realized oil price by $2.16 per Bbl during the three months ended September 30, 2011. During the three months ended September 30, 2010, our effective hedging transactions increased our average realized natural gas price by $0.96 per Mcf and decreased our average realized oil price by $2.79 per Bbl. During the nine months ended September 30, 2011, effective hedging transactions increased our average realized natural gas price by $0.43 per Mcf and decreased our average realized oil price by $5.43 per Bbl. During the nine months ended September 30, 2010, effective hedging transactions increased our average realized natural gas price by $0.81 per Mcf and decreased our average realized oil price by $4.26 per Bbl.

          Revenue.Oil and natural gas revenue was $207.7 million during the three months ended September 30, 2011, compared to $153.2 million during the comparable period of 2010. The increase is attributable to a 43% increase in average realized oil prices along with a 13% increase in oil production volumes, partially offset by a decline in average realized gas prices and gas production volumes. Oil and natural gas revenue for the nine months ended September 30, 2011 totaled $637.4 million compared to $481.0 million during the comparable period of 2010. The increase is attributable to a 41% increase in average realized oil prices along with a 14% increase in oil production volumes, partially offset by a decline in average realized gas prices and gas production volumes.

          Derivative Income/Expense.During the nine months ended September 30, 2011 and 2010, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. Net derivative income for the three months ended September 30, 2011, totaled $4.1 million, consisting of $0.1 million of cash settlements on the ineffective portion of derivative contracts, less $4.2 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative income for the three months ended September 30, 2010, totaled $0.4 million, consisting of $0.8 million of cash settlements on the ineffective derivative contracts, less $0.4 million of changes in the fair market value of the ineffective portion of derivative contracts.

          Net derivative income for the nine months ended September 30, 2011, totaled $3.3 million, consisting of $1.0 million of cash settlements on the ineffective portion of derivative contracts, less $4.3 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative income for the nine months ended September 30, 2010, totaled $3.8 million, consisting of $2.4 million of cash settlements on the ineffective derivative contracts, plus $1.4 million of changes in the fair market value of the ineffective portion of derivative contracts.

          Expenses.Lease operating expenses during the three months ended September 30, 2011 and 2010 totaled $47.8 million and $36.9 million, respectively. For the nine months ended September 30, 2011 and 2010, lease operating expenses totaled $133.3 million and $112.4 million, respectively. On a unit of production basis, lease operating expenses were $2.27 per Mcfe and $1.97 per Mcfe for the nine months ended September 30, 2011 and 2010, respectively. The increase in lease operating expenses in 2011 was primarily attributable to increased platform and well maintenance.

          The other operational expense charge of $0.7 million for 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. The other operational expense charge of $3.0 million for the three months ended September 30, 2010 included a $0.8 million loss on the sale of non-dedicated tubular inventory and $2.2 million of charges related to a delay in the drilling of the second well in our Amberjack drilling program as a result of the deep water drilling moratorium.

          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. For the nine months ended September 30, 2010,

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other operational expenses of $5.5 million included a $2.2 million loss on the sale of non-dedicated tubular inventory and a total of $3.3 million of charges related to a delay in the drilling of the second well in our Amberjack drilling program as a result of the deep water drilling moratorium.

          Depreciation, depletion and amortization (“DD&A”) on oil and gas properties for the three months ended September 30, 2011 totaled $63.8 million, or $3.38 per Mcfe, compared to $59.0 million, or $3.24 per Mcfe, during the comparable period of 2010. For the nine months ended September 30, 2011 and 2010, DD&A expense totaled $201.9 million, or $3.44 per Mcfe, and $180.4 million, or $3.16 per Mcfe, respectively. The increase in DD&A in 2011 on a unit basis was primarily 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.

          Accretion expense for the three months ended September 30, 2011 was $7.7 million compared to $8.5 million for the comparable period of 2010. For the nine months ended September 30, 2011 and 2010, accretion expense totaled $23.1 million and $25.4 million, respectively. The decrease is primarily due to a change in the timing on certain of our asset retirement obligations.

          Salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) for the three months ended September 30, 2011 were $7.2 million compared to $9.8 million for the three months ended September 30, 2010. The decrease is primarily the result of the settlement of litigation and a resulting significant reimbursement of legal fees incurred in prior periods. For the nine months ended September 30, 2011 and 2010, SG&A (exclusive of incentive compensation) totaled $29.5 million and $30.2 million, respectively.

          For the three months ended September 30, 2011 and 2010, incentive compensation expense totaled $2.1 million and $0.8 million, respectively. For the nine months ended September 30, 2011 and 2010, incentive compensation expense totaled $7.1 million and $2.1 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, 2011 totaled $1.4 million, net of $11.5 million of capitalized interest, compared to interest expense of $2.7 million, net of $8.0 million of capitalized interest, during the comparable 2010 period. For the nine months ended September 30, 2011, interest expense totaled $6.5 million, net of $32.0 million of capitalized interest, compared to interest expense of $9.3 million, net of capitalized interest of $21.6 million for the comparable 2010 period. The decrease in interest expense is primarily the result of an increase in the amount of interest capitalized as a part of the cost oil and gas properties.

          Our effective tax rate was 34.7% and 35.8% for the three and nine months ended September 30, 2011, respectively, and 39.2% and 36.4% for the comparable 2010 periods. The decreased effective tax rate for the three and nine-month periods relates to the finalization of permanent deductions in the filing of prior period amended returns. Additionally, the effective tax rate for the quarter ended September 30, 2010 was impacted by the cumulative effect of higher effective state income tax rates resulting from increased onshore activities.

Off Balance Sheet Arrangements

          None.

Recent Accounting Developments

          None.

Defined Terms

          Oil and condensate 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 and condensate 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.

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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 without the consent of the board of directors. We believe our current hedging positions have hedged approximately 43% of our estimated 2011 production, 39% of our estimated 2012 production from estimated proved reserves, 27% of our estimated 2013 production from estimated proved reserves and 4% of our estimated 2014 production from estimated proved reserves. SeeItem 1. Financial Statements — Note 3 — Derivative Instruments and Hedging Activitiesfor a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

          Since the filing of our Annual Report on Form 10-K for the year ended December 31, 2010, 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 $575 million at September 30, 2011, all of which bears interest at fixed rates. The $575 million of fixed-rate debt is comprised of $375 million of 8⁵/8% Senior Notes due 2017 and $200 million of 6³/4% Senior Subordinated Notes due 2014. We had no outstanding borrowings under our variable-rate bank credit facility during the nine months ended September 30, 2011. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

          We have established disclosure controls and procedures to ensure that material information relating to Stone Energy Corporation and its consolidated subsidiaries (collectively “Stone”) is made known to the officers who certify Stone’s financial reports and the Board of Directors. Disclosure controls and procedures, as defined in the rules and regulations of the Securities Exchange Act of 1934, means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

          Our principal executive officer and our principal financial officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of Stone’s disclosure controls and procedures as of the end of the quarterly period ended September 30, 2011. Based on this evaluation, our principal executive officer and principal financial officer believe that as of the end of the quarterly period ended September 30, 2011:

• Stone’s disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and

• Stone’s disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports that it files or submits under the Securities Exchange Act of 1934 was accumulated and

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communicated to Stone’s management, including Stone’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

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, 2011 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 Louisiana Department of Revenue (“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 calculated through December 15, 2005 in the amount of $1.2 million. 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 calculated through October 21, 2008 in the amount of $1.7 million. In addition, we have received assessments from the LDR for additional franchise taxes in the amount of $2.9 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 Outer Continental Shelf, 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. The Company disagrees with these contentions and intends to vigorously defend itself against these claims. The franchise tax year 2010 for Stone remains subject to examination.

          Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet,et al., filed civil action No. 110741 in the 17^th Judicial District Court, Lafourche Parish, Louisiana, against Stone. Plaintiffs subsequently filed three supplemental petitions, including a third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs alleged that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs in excess of $60 million. Plaintiffs’ expert witness provided his report, dated December 28, 2010, stating his opinion that one well did not produce as much production as it should have, resulting in a loss to plaintiffs “in excess of $4 million,” that imprudent operations destroyed hydrocarbon bearing zones resulting in a loss to plaintiffs “in excess of $20 million,” and that imprudent operation of a water injection secondary recovery project resulted in damages to plaintiffs of “approximately $4,755,000.” There were also allegations of failure to protect from drainage from a well on adjoining land, trespass, and various other breaches of the mineral leases. The Company disagreed with plaintiffs’ contentions. In October 2011, the parties agreed to a settlement of all claims asserted in this action, and we anticipate that the settlement will be effected not later than January 2012. The settlement will not have a materially adverse effect on the Company.

          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 Stone’s Annual Report on Form 10-K for the year ended December 31, 2010.

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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, 2011:

								Maximum Number (or
						Total Number of		Approximate Dollar
						Shares (or Units)		Value) of Shares
						Purchased as Part		(or Units) that May
	Total Number of					of Publicly		Yet be Purchased
	Shares (or Units)			Average Price Paid		Announced Plans or		Under the Plans or
Period	Purchased			per Share (or Unit)		Programs		Programs
Share Repurchase Program:
July 2011		—			—		—
August 2011		—			—		—
September 2011		—			—		—
		—			—		—	$	92,928,632
Other:
July 2011		4,807	(a)	$	30.71		—
August 2011		—			—		—
September 2011		22,069	(a)		26.12		—
		26,876		$	26.94	��	—		N/A
Total		26,876		$	26.94		—

(a) Amounts include shares withheld from employees upon the vesting of restricted stock in order to satisfy the required tax withholding obligations.

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Item 6. Exhibits

3.1	Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).
3.2	Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K, filed February 7, 2001).
3.3	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 dated May 15, 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 on December 15, 2004.)
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	First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)).
*15.1	Letter from Ernst & Young LLP dated November 7, 2011, regarding unaudited interim financial information.
*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

30

**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.
†	Identifies management contracts and compensatory plans or arrangements.

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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 hereunto duly authorized.

	STONE ENERGY CORPORATION
Date: November 7, 2011	By:	/s/ J. Kent Pierret
		J. Kent Pierret
		Senior Vice President, Chief Accounting Officer and Treasurer (On behalf of the Registrant and as Chief Accounting Officer)

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EXHIBIT INDEX

Exhibit Number	Description
3.1	Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).
3.2	Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K, filed February 7, 2001).
3.3	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 dated May 15, 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 on December 15, 2004.)
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	First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)).
*15.1	Letter from Ernst & Young LLP dated November 7, 2011, regarding unaudited interim financial information.
*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

33

Exhibit Number	Description
**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.
†	Identifies management contracts and compensatory plans or arrangements.

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