Stone Energy (SGY) 10-Q 2010 Q2 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 June 30, 2010

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

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). Yeso 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 August 4, 2010, there were 48,559,830 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 June 30, 2010 and December 31, 2009		1
Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2010 and 2009		2
Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2010 and 2009		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		26
Item 4. Controls and Procedures		27
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		29
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 6. Exhibits		32
Signature		33
EX-15.1
EX-31.1
EX-31.2
EX-32.1

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	June 30,			December 31,
	2010			2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	77,265		$	69,293
Accounts receivable		112,236			118,129
Fair value of hedging contracts		24,977			16,223
Deferred tax asset		1,245			14,571
Inventory		7,781			8,717
Other current assets		962			814
Total current assets		224,466			227,747
Oil and gas properties — United States — full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $4,658,493 and $4,536,599, respectively		820,130			856,467
Unevaluated		378,314			329,242
Building and land, net		5,713			5,723
Fair value of hedging contracts		10,117			1,771
Fixed assets, net		4,117			4,084
Other assets, net		21,453			29,208
Total assets	$	1,464,310		$	1,454,242
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	66,644		$	66,863
Undistributed oil and gas proceeds		20,413			15,280
Fair value of hedging contracts		12,609			34,859
Asset retirement obligations		30,995			30,515
Current income tax payable		2,297			11,110
Other current liabilities		16,381			42,983
Total current liabilities		149,339			201,610
Long-term debt		525,000			575,000
Deferred taxes		82,032			44,528
Asset retirement obligations		257,897			265,021
Fair value of hedging contracts		2,006			7,721
Other long-term liabilities		19,291			18,412
Total liabilities		1,035,565			1,112,292
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 47,703,799 and 47,509,144 shares, respectively		477			475
Treasury stock (16,582 shares, respectively, at cost)		(860	)		(860	)
Additional paid-in capital		1,327,390			1,324,410
Accumulated deficit		(910,992	)		(966,695	)
Accumulated other comprehensive income (loss)		12,730			(15,380	)
Total stockholders’ equity		428,745			341,950
Total liabilities and stockholders’ equity	$	1,464,310		$	1,454,242

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

1

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Operating revenue:
Oil production	$	103,159		$	107,972		$	203,724		$	178,826
Gas production		60,823			62,340			124,049			130,490
Derivative income, net		2,225			—			3,413			3,196
Total operating revenue		166,207			170,312			331,186			312,512
Operating expenses:
Lease operating expenses		36,883			41,122			75,547			99,276
Other operational expense		2,447			2,400			2,447			2,400
Production taxes		1,590			2,565			3,244			3,840
Depreciation, depletion and amortization		63,765			57,052			124,418			117,670
Write-down of oil and gas properties		—			—			—			340,083
Accretion expense		6,606			8,376			13,212			16,753
Salaries, general and administrative expenses		9,963			9,922			20,448			21,583
Incentive compensation expense		421			1,197			1,346			1,417
Impairment of inventory		—			1,256			—			7,179
Derivative expenses, net		—			743			—			—
Total operating expenses		121,675			124,633			240,662			610,201
Income (loss) from operations		44,532			45,679			90,524			(297,689	)
Other (income) expenses:
Interest expense		2,540			4,788			6,606			9,954
Interest income		(1,002	)		(146	)		(1,059	)		(282	)
Other income		(1,419	)		(851	)		(3,451	)		(2,253	)
Early extinguishment of debt		—			—			1,820			—
Other expense		197			—			477			428
Total other (income) expenses		316			3,791			4,393			7,847
Net income (loss) before income taxes		44,216			41,888			86,131			(305,536	)
Provision (benefit) for income taxes:
Current		(1,392	)		—			(5,264	)		23
Deferred		16,529			14,720			35,692			(106,888	)
Total income taxes		15,137			14,720			30,428			(106,865	)
Net income (loss)		29,079			27,168			55,703			(198,671	)
Less: Net income attributable to non-controlling interest		—			—			—			27
Net income (loss) attributable to Stone Energy Corporation	$	29,079		$	27,168		$	55,703		$	(198,698	)
Basic income (loss) per share attributable to Stone Energy Corporation stockholders	$	0.60		$	0.65		$	1.15		$	(4.92	)
Diluted income (loss) per share attributable to Stone Energy Corporation stockholders	$	0.60		$	0.65		$	1.15		$	(4.92	)
Average shares outstanding		47,654			41,270			47,631			40,365
Average shares outstanding assuming dilution		47,678			41,270			47,657			40,365

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)

	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	55,703		$	(198,671	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		124,418			117,670
Write-down of oil and gas properties		—			340,083
Impairment of inventory		—			7,179
Accretion expense		13,212			16,753
Deferred income tax provision (benefit)		35,692			(106,888	)
Settlement of asset retirement obligations		(19,798	)		(28,249	)
Non-cash stock compensation expense		2,741			3,159
Excess tax benefits		(294	)		—
Non-cash derivative (income) expense		(1,818	)		1,902
Early extinguishment of debt		1,820			—
Other non-cash expenses		519			923
Unrecognized proceeds from unwound derivative contracts		—			71,662
Change in current income taxes		(8,813	)		30,435
Decrease in accounts receivable		27,500			17,638
(Increase) decrease in other current assets		(153	)		271
Decrease in inventory		936			15,950
Increase (decrease) in accounts payable		(15	)		11,397
Decrease in other current liabilities		(21,469	)		(27,765	)
Other		153			94
Net cash provided by operating activities		210,334			273,543
Cash flows from investing activities:
Investment in oil and gas properties		(169,983	)		(197,001	)
Proceeds from sale of oil and gas properties, net of expenses		29,727			5,496
Sale of fixed assets		—			35
Investment in fixed and other assets		(1,125	)		(376	)
Acquisition of non-controlling interest in subsidiary		—			(40	)
Net cash used in investing activities		(141,381	)		(191,886	)
Cash flows from financing activities:
Net proceeds from issuance of common stock		—			60,456
Repayments of bank borrowings		(125,000	)		(100,000	)
Redemption of senior subordinated notes		(200,503	)		—
Proceeds from issuance of senior notes		275,000			—
Deferred financing costs		(9,701	)		(175	)
Excess tax benefits		294			—
Purchase of treasury stock		—			(347	)
Net payments for share based compensation		(1,071	)		(389	)
Net cash used in financing activities		(60,981	)		(40,455	)
Net increase in cash and cash equivalents		7,972			41,202
Cash and cash equivalents, beginning of period		69,293			68,137
Cash and cash equivalents, end of period	$	77,265		$	109,339

The accompanying notes are an integral part of this statement.

3

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 June 30, 2010 and for the three and six-month periods ended June 30, 2010 and 2009 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, 2009 has been derived from the audited financial statements at that date. The 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, 2009. The results of operations for the three and six-month periods ended June 30, 2010 are not necessarily indicative of future financial results.

Note 2 — Earnings Per Share

     Under U.S. Generally Accepted Accounting Principles (“GAAP”), instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share. This rule became effective for us on January 1, 2009 and the net effect of its implementation on our financial statements was immaterial.

     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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(in thousands, except per share data)
Income (numerator):
Net income (loss)	$	29,079		$	27,168		$	55,703		$	(198,698	)
Net income attributable to participating securities		(506	)		(369	)		(969	)		—
Net income (loss) attributable to common stock — basic and diluted	$	28,573		$	26,799		$	54,734		$	(198,698	)
Weighted average shares (denominator):
Weighted average shares — basic		47,654			41,270			47,631			40,365
Diluted effect of stock options and unvested restricted stock		24			—			26			—
Weighted average shares — diluted		47,678			41,270			47,657			40,365
Basic income (loss) per common share	$	0.60		$	0.65		$	1.15		$	(4.92	)
Diluted income (loss) per common share	$	0.60		$	0.65		$	1.15		$	(4.92	)

     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 422,000 and 501,000 shares in the three months ended June 30, 2010 and 2009, respectively. Stock options that were considered antidilutive totaled 423,000 and 501,000 shares during the six months ended June 30, 2010 and 2009, respectively.

     During the three months ended June 30, 2010 and 2009, respectively, approximately 55,000 and 20,000 shares of common stock were issued upon the vesting of restricted stock by employees and nonemployee directors. On June 10, 2009, 8,050,000 shares of common stock were issued in a public offering.

4

     During the six months ended June 30, 2010 and 2009, respectively, approximately 195,000 and 105,000 shares of common stock were issued upon the vesting of restricted stock by employees and nonemployee directors. During the six months ended June 30, 2009, 100,000 shares of common stock were repurchased under our stock repurchase program.

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 contract. 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 2010, 2011 and 2012 oil and natural gas production from the Gulf Coast Basin. The 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. Some of our fixed-price gas swap settlements are based on an average of NYMEX prices for the last three days of a respective month and some 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 outstanding fixed-price swap contracts are with J.P. Morgan Chase Bank, N.A., The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia and Bank of America.

     During 2009, a portion of our oil and natural gas production was hedged with zero-premium collars. The oil collar settlements are based on an average of the NYMEX closing price for WTI during the entire calendar month. The natural gas collar settlements are based on an average of NYMEX prices for the last three days of a respective month. The collar contracts require payments to the counterparties if the average price is above the ceiling price or payment from the counterparties if the average price is below the floor price.

     During the six-month periods ended June 30, 2010 and 2009, 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.

5

     All of our derivative instruments at June 30, 2010 and December 31, 2009 were designated as effective cash flow hedges. The following tables disclose the location and fair value amounts of derivative instruments reported in our balance sheet at June 30, 2010 and December 31, 2009.

Fair Value of Derivative Instruments at June 30, 2010
(in millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair			Current liabilities:
	value of hedging			Fair value of hedging
	contracts	$	25.0	contracts	$	(12.6	)
	Long-term assets:			Long-term liabilities: Fair
	Fair value of hedging			value of hedging
	contracts		10.1	contracts		(2.0	)
		$	35.1		$	(14.6	)

Fair Value of Derivative Instruments at December 31, 2009
(in millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair			Current liabilities:
	value of hedging			Fair value of hedging
	contracts	$	16.2	contracts	$	(34.9	)
	Long-term assets:			Long-term liabilities: Fair
	Fair value of hedging			value of hedging
	contracts		1.8	contracts		(7.7	)
		$	18.0		$	(42.6	)

     The following tables disclose the effect of derivative instruments in the statement of operations for the three and six-month periods ended June 30, 2010 and 2009.

The Effect of Derivative Instruments on the Statement of Operations for the Three Months Ended June 30, 2010 and 2009
(in millions)
Derivatives in	Amount of Gain (Loss) Recognized					Gain (Loss) Reclassified from
Cash Flow Hedging	in OCI on Derivative					Accumulated OCI into Income					Gain (Loss) Recognized in Income on
Relationships	(Effective Portion)					(Effective Portion) (a)					Derivative (Ineffective Portion)
	2010		2009			Location	2010		2009		Location	2010		2009
Commodity contracts	$	15.0	$	(45.6	)	Operating revenue - oil/gas production	$	4.8	$	44.9	Derivative income, net	$	2.2	$	(0.7	)
Total	$	15.0	$	(45.6	)		$	4.8	$	44.9		$	2.2	$	(0.7	)

(a) For the three months ended June 30, 2010, effective hedging contracts reduced oil revenue by $5.8 million and increased gas revenue by $10.6 million. For the three months ended June 30, 2009, effective hedging contracts increased oil revenue by $19.4 million and increased gas revenue by $25.5 million.

The Effect of Derivative Instruments on the Statement of Operations for the Six Months Ended June 30, 2010 and 2009
(in millions)
Derivatives in	Amount of Gain (Loss)					Gain (Loss) Reclassified from
Cash Flow Hedging	Recognized in OCI on Derivative					Accumulated OCI into Income					Gain (Loss) Recognized in Income on
Relationships	(Effective Portion)					(Effective Portion) (a)					Derivative (Ineffective Portion)
	2010		2009			Location	2010		2009		Location	2010		2009
Commodity contracts	$	28.1	$	(40.4	)	Operating revenue - oil/gas production	$	2.2	$	85.7	Derivative income, net	$	3.4	$	3.2
Total	$	28.1	$	(40.4	)		$	2.2	$	85.7		$	3.4	$	3.2

(a) For the six months ended June 30, 2010, effective hedging contracts reduced oil revenue by $14.1 million and increased gas revenue by $16.3 million. For the six months ended June 30, 2009, effective hedging contracts increased oil revenue by $37.7 million and increased gas revenue by $48.0 million.

     On March 3, 2009, we unwound all of our existing crude oil hedges for the period from April 2009 through December 2009, resulting in proceeds of approximately $59 million. On March 6, 2009, we unwound two of our natural gas hedges for the period from April 2009 through December 2009, resulting in proceeds of approximately $54 million. These amounts (net of the ineffective portion and related deferred income tax effect) were recorded in accumulated other comprehensive income in 2009. As the original time periods for these contracts expired, applicable amounts were reclassified into earnings.

6

     At June 30, 2010, we had accumulated other comprehensive income of $12.7 million, net of tax, which related to the fair value of our 2010, 2011 and 2012 swap contracts. We believe that approximately $7.5 million of accumulated other comprehensive income will be reclassified into earnings in the next twelve months.

     The following table illustrates our hedging positions for calendar years 2010, 2011 and 2012 as of August 4, 2010:

	Fixed-Price Swaps
	Natural Gas		Oil
		Swap	Daily Volume	Swap
	Daily Volume (MMBtus/d)	Price	(Bbls/d)	Price
2010	20,000	$6.97	2,000	$63.00
2010	30,000	6.50	1,000	64.05
2010			1,000	60.20
2010			1,000	75.00
2010			1,000	75.25
2010			2,000 (a)	80.10
2010			1,000 (b)	84.35
2011	10,000	6.83	1,000	70.05
2011	10,000	5.20	1,000	78.20
2011			1,000	83.00
2011			1,000	83.05
2011			1,000 (c)	85.20
2011			1,000	85.25
2012			1,000	90.45
2012			1,000	90.30

(a)	April — December
(b)	July — December
(c)	January — June

Note 4 — Long-Term Debt

     Long-term debt consisted of the following at:

	June 30,		December 31,
	2010		2009
	(in millions)
81/4% Senior Subordinated Notes due 2011	$	—	$	200.0
63/4% Senior Subordinated Notes due 2014		200.0		200.0
85/8% Senior Notes due 2017		275.0		—
Bank debt		50.0		175.0
Total long-term debt	$	525.0	$	575.0

     On August 28, 2008, we entered into an amended and restated revolving credit facility totaling $700 million, maturing on July 1, 2011, with a syndicated bank group. Our borrowing base under our bank credit facility is currently set at $395 million. At June 30, 2010, we had $50 million in borrowings under our bank credit facility, letters of credit totaling $63.1 million had been issued pursuant to our bank credit facility, and the weighted average interest rate under our bank credit facility was approximately 2.6%. As of August 4, 2010, we had $50 million of outstanding borrowings under our bank credit facility and letters of credit totaling $63.1 million had been issued pursuant to our bank credit facility, leaving $281.9 million of availability under our bank credit facility. Our bank credit facility is guaranteed by all of our material direct and indirect subsidiaries, including Stone Energy Offshore, L.L.C. (“Stone Offshore”), a wholly owned subsidiary of Stone.

     The borrowing base under our bank credit facility is redetermined semi-annually, typically in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At Stone’s 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.

7

     On January 26, 2010, we completed a public offering of $275 million aggregate principal amount of 8⁵/₈% Senior Notes due 2017 (the “2017 Notes”) which are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $265 million. The 2017 Notes rank equally in right of payment with all of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt, including our outstanding senior subordinated notes. The 2017 Notes mature on February 1, 2017, and interest is payable on each February 1 and August 1, commencing on August 1, 2010. We may, at our option, redeem all or part of the 2017 Notes at any time prior to February 1, 2014 at a make-whole redemption price, and at any time on or after February 1, 2014 at fixed redemption prices. In addition, prior to February 1, 2013, we may, at our option, redeem up to 35% of the 2017 Notes with the cash proceeds of certain equity offerings. The 2017 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2017 Notes a right to accelerate payment. At June 30, 2010, $10.2 million had been accrued in connection with the August 1, 2010 interest payment.

     In the first quarter of 2010, we used the proceeds from the 8⁵/₈% Senior Notes offering to purchase and redeem our 8¹/4% Senior Subordinated Notes due 2011. The total cost of the transaction was $202.4 million which included $200.5 million to purchase and redeem the notes plus accrued and unpaid interest of $1.9 million. The transaction resulted in a charge to earnings of approximately $1.8 million in the first quarter of 2010.

Note 5 — Comprehensive Income

     The following table illustrates the components of comprehensive income for the three and six-month periods ended June 30, 2010 and 2009:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
	(in millions)
Net income (loss)	$	29.1	$	27.2		$	55.7	$	(198.7	)
Other comprehensive loss, net of tax effect:
Adjustment for fair value accounting of derivatives		15.0		(45.6	)		28.1		(40.4	)
Comprehensive income (loss) attributable to Stone Energy Corporation	$	44.1	$	(18.4	)	$	83.8	$	(239.1	)

Note 6 — Asset Retirement Obligations

     The change in our asset retirement obligations during the six months ended June 30, 2010 is set forth below:

	Six Months Ended
	June 30, 2010
	(in millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	295.5
Liabilities settled		(19.8	)
Accretion expense		13.2
Asset retirement obligations as of the end of the period, including current portion	$	288.9

Note 7— Impairments

     Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves, to the net capitalized costs of proved oil and gas properties net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. At March 31, 2009, our ceiling test computation resulted in a write-down of our oil and gas properties of $340.1 million based on a March 31, 2009 Henry Hub gas price of $3.63 per MMBtu and a West Texas Intermediate oil price of $44.92 per barrel. The benefit of hedges in place at March 31, 2009 reduced the write-down by $85.0 million.

     For the six months ended June 30, 2009, we recorded a write-down of our tubular inventory in the amount of $7.2 million. This charge was the result of the market value of these tubulars falling below historical cost.

8

Note 8— Fair Value Measurements

     U.S. GAAP establishes 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.

     The Financial Accounting Standards Board (“FASB”) issued updated guidance in January 2010 to improve disclosures about fair value measurements by requiring a greater level of disaggregated information, more robust disclosures about valuation techniques and inputs to fair value measurements, information about significant transfers between the three levels in the fair value hierarchy, and separate presentation of information about purchases, sales, issuances, and settlements on a gross basis rather than as one net number. This guidance became effective for us on January 1, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.

     As of June 30, 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 the credit risk of Stone and its counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy and collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call and put portions of the collar. 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:

	Fair Value Measurements at June 30, 2010
			Quoted Prices
			in Active Markets
			for Identical		Significant Other		Significant
			Assets		Observable Inputs		Unobservable Inputs
	Total		(Level 1)		(Level 2)		(Level 3)
	(in millions)
Assets
Money market funds	$	6.1	$	6.1	$	—	$	—
Hedging contracts		35.1		—		35.1		—
Total	$	41.2	$	6.1	$	35.1	$	—

	Fair Value Measurements at June 30, 2010
				Quoted Prices
				in Active Markets
				for Identical		Significant Other			Significant
				Liabilities		Observable Inputs			Unobservable Inputs
	Total			(Level 1)		(Level 2)			(Level 3)
	(in millions)
Liabilities
Hedging contracts	$	(14.6	)	$	—	$	(14.6	)	$	—
Total	$	(14.6	)	$	—	$	(14.6	)	$	—

     The fair value of cash and cash equivalents, accounts receivable, accounts payable to vendors and our variable-rate bank debt approximated book value at June 30, 2010 and December 31, 2009. As of June 30, 2010, the fair value of our $275 million 8⁵/₈% Senior Notes due 2017 was approximately $248 million. As of December 31, 2009, the fair value of our $200 million 8¹/4% Senior Subordinated Notes due 2011 was approximately $200 million. In the first quarter of 2010, we used the proceeds from the 8⁵/₈% Senior Notes offering to purchase and redeem our 8¹/4% Senior Subordinated Notes due 2011. As of June 30, 2010 and December 31, 2009, the fair value of our $200 million 6³/4% Senior Subordinated Notes due 2014 was approximately $171 million and $178 million, respectively. The fair values of our outstanding notes were determined based upon quotes obtained from brokers.

9

Note 9 — Divestitures

     In April 2010, we divested our leasehold interest in approximately 7,000 acres in the Marcellus Shale for approximately $29 million.

Note 10 — Commitments and Contingencies

     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 a subsidiary. 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 to date amount to approximately $20.2 million in additional franchise taxes and estimated accrued interest. The franchise tax years 2007 through 2009 for Stone remain subject to examination, which potentially exposes us to additional estimated assessments of $6.1 million including accrued interest.

     Ad Valorem Tax Suit.In August 2009, Gene P. Bonvillain, in his capacity as Assessor for the Parish of Terrebonne, State of Louisiana, filed civil action No. 90-03540 and other consolidated cases in the United States District Court for the Eastern District of Louisiana against approximately thirty oil and gas companies, including Stone, and their respective chief executive officers for allegedly unpaid ad valorem taxes. The amount originally alleged to be due by Stone for the years 1998 through 2008 was $11.3 million. The defendants were subsequently served and filed motions to dismiss this litigation pursuant to Rule 12(b)(6) of the Federal Rules of Civil Procedure. On March 29, 2010, the trial court judge dismissed plaintiff’s claims without prejudice, with the dismissal to become effective within ten days unless plaintiff filed an amended complaint correcting its deficiencies. On April 8, 2010, plaintiff filed a first amended complaint without naming any of the chief executive officers as defendants and with an amount allegedly due by Stone of “not less than” $3.5 million. Subsequently, defendants filed motions to dismiss this litigation, and the trial court judge granted these motions to dismiss on July 26, 2010.

     Stone’s Certificate of Incorporation and/or its Restated Bylaws provide, to the extent permissible under the law of the State of Delaware (Stone’s state of incorporation), for indemnification of and advancement of defense costs to Stone’s current and former directors and officers for potential liabilities related to their service to Stone. Stone has purchased directors and officers insurance policies that, under certain circumstances, may provide coverage to Stone and/or its officers and directors for certain losses resulting from securities-related civil liabilities and/or the satisfaction of indemnification and advancement obligations owed to directors and officers. These insurance policies may not cover all costs and liabilities incurred by Stone and its current and former officers and directors in these regulatory and civil proceedings.

Note 11 — Income Taxes

     The following is a reconciliation of unrecognized tax benefits for the six months ended June 30, 2010:

	(in millions)
Total unrecognized tax benefits as of December 31, 2009	$	25.7
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		0.8
Tax positions taken during the current period		—
Settlements with taxing authorities		(24.5	)
Lapse of applicable statute of limitations		(1.2	)
Total unrecognized tax benefits as of June 30, 2010	$	0.8

     We had a net benefit of $0.4 million in the current period as a result of net amounts recognized that impacted our effective rate. In addition, we recognized a $1.2 million net credit to interest expense associated with additions and reductions to unrecognized tax benefits. The entire balance of unrecognized tax benefits at June 30, 2010 would impact our tax rate if recognized.

10

Note 12 — 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 June 30, 2010 and December 31, 2009 and for the three and six-month periods ended June 30, 2010 and 2009 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, and consolidated basis. Prior periods have been adjusted to reflect a change in the allocation of amounts to individual entities. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
JUNE 30, 2010
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	75,946		$	1,203		$	116		$	—		$	77,265
Accounts receivable		54,526			303,865			474			(246,629	)		112,236
Fair value of hedging contracts		24,977			—			—			—			24,977
Deferred tax asset		1,245			—			—			—			1,245
Inventory		7,331			450			—			—			7,781
Other current assets		919			43			—			—			962
Total current assets		164,944			305,561			590			(246,629	)		224,466
Oil and gas properties — United States
Proved, net		83,532			731,702			4,896			—			820,130
Unevaluated		272,603			105,711			—			—			378,314
Building and land, net		5,713			—			—			—			5,713
Fair value of hedging contracts		10,117			—			—			—			10,117
Fixed assets, net		4,117			—			—			—			4,117
Other assets, net		21,453			—			—			—			21,453
Investment in subsidiary		805,698			641			—			(806,339	)		—
Total assets	$	1,368,177		$	1,143,615		$	5,486		$	(1,052,968	)	$	1,464,310
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	278,489		$	34,773		$	11		$	(246,629	)	$	66,644
Undistributed oil and gas proceeds		19,840			573			—			—			20,413
Fair value of hedging contracts		12,609			—			—			—			12,609
Asset retirement obligations		9,608			21,387			—			—			30,995
Current income tax payable		2,297			—			—			—			2,297
Other current liabilities		16,003			378			—			—			16,381
Total current liabilities		338,846			57,111			11			(246,629	)		149,339
Long-term debt		525,000			—			—			—			525,000
Deferred taxes *		(15,374	)		97,406			—			—			82,032
Asset retirement obligations		76,375			176,688			4,834			—			257,897
Fair value of hedging contracts		2,006			—			—			—			2,006
Other long-term liabilities		12,579			6,712			—			—			19,291
Total liabilities		939,432			337,917			4,845			(246,629	)		1,035,565
Commitments and contingencies
Stockholders’ equity:
Common stock		477			—			—			—			477
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,327,390			2,125,517			1,639			(2,127,156	)		1,327,390
Retained earnings (deficit)		(910,992	)		(1,319,819	)		(998	)		1,320,817			(910,992	)
Accumulated other comprehensive income		12,730			—			—			—			12,730
Total stockholders’ equity		428,745			805,698			641			(806,339	)		428,745
Total liabilities and stockholders’ equity	$	1,368,177		$	1,143,615		$	5,486		$	(1,052,968	)	$	1,464,310

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

11

CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
DECEMBER 31, 2009
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	64,830		$	3,963		$	500		$	—		$	69,293
Accounts receivable		53,396			169,053			144			(104,464	)		118,129
Fair value of hedging contracts		16,223			—			—			—			16,223
Deferred tax asset		14,571			—			—			—			14,571
Inventory		8,145			572			—			—			8,717
Other current assets		771			43			—			—			814
Total current assets		157,936			173,631			644			(104,464	)		227,747
Oil and gas properties — United States
Proved, net		76,066			774,980			5,421			—			856,467
Unevaluated		226,289			102,953			—			—			329,242
Building and land, net		5,723			—			—			—			5,723
Fair value of hedging contracts		1,771												1,771
Fixed assets, net		4,084			—			—			—			4,084
Other assets, net		29,208			—			—			—			29,208
Investment in subsidiary		739,834			890			—			(740,724	)		—
Total assets	$	1,240,911		$	1,052,454		$	6,065			($845,188	)	$	1,454,242
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	135,518		$	35,247		$	562			($104,464	)	$	66,863
Undistributed oil and gas proceeds		14,828			452			—			—			15,280
Fair value of hedging contracts		34,859			—			—			—			34,859
Asset retirement obligations		9,597			20,918			—			—			30,515
Current income tax payable		11,110			—			—			—			11,110
Other current liabilities		42,223			760			—			—			42,983
Total current liabilities		248,135			57,377			562			(104,464	)		201,610
Long-term debt		575,000			—			—			—			575,000
Deferred taxes *		(17,459	)		61,987			—			—			44,528
Asset retirement obligations		73,864			186,545			4,612			—			265,021
Fair value of hedging contracts		7,721			—			—			—			7,721
Other long-term liabilities		11,700			6,712			—			—			18,412
Total liabilities		898,961			312,621			5,174			(104,464	)		1,112,292
Commitments and contingencies
Stockholders’ equity:
Common stock		475			—			—			—			475
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,324,410			2,125,517			1,639			(2,127,156	)		1,324,410
Retained earnings (deficit)		(966,695	)		(1,385,684	)		(748	)		1,386,432			(966,695	)
Accumulated other comprehensive loss		(15,380	)		—			—			—			(15,380	)
Total stockholders’ equity		341,950			739,833			891			(740,724	)		341,950
Total liabilities and stockholders’ equity	$	1,240,911		$	1,052,454		$	6,065			($845,188	)	$	1,454,242

* 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 JUNE 30, 2010
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	13,533		$	89,626		$	—		$	—		$	103,159
Gas production		16,406			44,417			—			—			60,823
Derivative income, net		2,225			—			—			—			2,225
Total operating revenue		32,164			134,043			—			—			166,207
Operating expenses:
Lease operating expenses		6,285			30,598			—			—			36,883
Other operational expense		1,275			1,172			—			—			2,447
Production taxes		1,256			334			—			—			1,590
Depreciation, depletion, amortization		10,318			53,170			277			—			63,765
Accretion expense		1,771			4,724			111			—			6,606
Salaries, general and administrative		9,960			3			—			—			9,963
Incentive compensation expense		421			—			—			—			421
Total operating expenses		31,286			90,001			388			—			121,675
Income (loss) from operations		878			44,042			(388	)		—			44,532
Other (income) expenses:
Interest expense		2,563			(23	)		—			—			2,540
Interest income		(1,002	)		—			—			—			(1,002	)
Other (income) expense, net		(1,009	)		17			(230	)		—			(1,222	)
(Income) loss from investment in subsidiary		(28,617	)		158			—			28,459			—
Total other (income) expenses		(28,065	)		152			(230	)		28,459			316
Income (loss) before taxes		28,943			43,890			(158	)		(28,459	)		44,216
Provision (benefit) for income taxes:
Current		(1,304	)		(88	)		—			—			(1,392	)
Deferred		1,168			15,361			—			—			16,529
Total income taxes		(136	)		15,273			—			—			15,137
Net income (loss)	$	29,079		$	28,617			($158	)		($28,459	)	$	29,079

13

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
THREE MONTHS ENDED JUNE 30, 2009
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	36,540		$	71,432		$	—		$	—		$	107,972
Gas production		30,512			31,828			—			—			62,340
Total operating revenue		67,052			103,260			—			—			170,312
Operating expenses:
Lease operating expenses		7,958			33,164			—			—			41,122
Other operational expense		2,400			—			—			—			2,400
Production taxes		2,334			231			—			—			2,565
Depreciation, depletion, amortization		10,495			46,494			63			—			57,052
Accretion expense		2,564			5,800			12			—			8,376
Salaries, general and administrative		9,929			(7	)		—			—			9,922
Incentive compensation expense		1,197			—			—			—			1,197
Impairment of inventory		845			411			—			—			1,256
Derivative expense, net		743			—			—			—			743
Total operating expenses		38,465			86,093			75			—			124,633
Income (loss) from operations		28,587			17,167			(75	)		—			45,679
Other (income) expenses:
Interest expense		4,770			18			—			—			4,788
Interest income		(146	)		—			—			—			(146	)
Other (income) expense, net		(701	)		(183	)		33			—			(851	)
(Income) loss from investment in subsidiary		(11,187	)		109			—			11,078			—
Total other (income) expenses		(7,264	)		(56	)		33			11,078			3,791
Income (loss) before taxes		35,851			17,223			(108	)		(11,078	)		41,888
Provision for income taxes:
Current		—			—			—			—			—
Deferred		8,681			6,039			—			—			14,720
Total income taxes		8,681			6,039			—			—			14,720
Net income (loss)	$	27,170		$	11,184			($108	)		($11,078	)	$	27,168

14

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

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations				Consolidated
Operating revenue:
Oil production	$	24,609		$	179,115		$	—		$	—			$	203,724
Gas production		29,424			94,625			—			—				124,049
Derivative income, net		3,413			—			—			—				3,413
Total operating revenue		57,446			273,740			—			—				331,186
Operating expenses:
Lease operating expenses		17,196			58,351			—			—				75,547
Other operational expense		1,275			1,172			—			—				2,447
Production taxes		2,309			935			—			—				3,244
Depreciation, depletion, amortization		20,826			103,049			543			—				124,418
Accretion expense		3,542			9,449			221			—				13,212
Salaries, general and administrative		20,442			6			—			—				20,448
Incentive compensation expense		1,346			—			—			—				1,346
Total operating expenses		66,936			172,962			764			—		��		240,662
Income (loss) from operations		(9,490	)		100,778			(764	)		—				90,524
Other (income) expenses:
Interest expense		6,629			(23	)		—			—				6,606
Interest income		(1,057	)		(2	)		—			—				(1,059	)
Other (income) expense, net		(1,818	)		(642	)		(514	)		—				(2,974	)
Early extinguishment of debt		1,820			—			—			—				1,820
(Income) loss from investment in subsidiary		(65,865	)		250			—			65,615				—
Total other (income) expenses		(60,291	)		(417	)		(514	)		65,615				4,393
Income (loss) before taxes		50,801			101,195			(250	)		(65,615	)			86,131
Provision (benefit) for income taxes:
Current		(5,176	)		(88	)		—			—				(5,264	)
Deferred		274			35,418			—			—				35,692
Total income taxes		(4,902	)		35,330			—			—				30,428
Net income (loss)	$	55,703		$	65,865			($250	)		($65,615	)		$	55,703

15

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
SIX MONTHS ENDED JUNE 30, 2009
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	66,450		$	112,376		$	—		$	—		$	178,826
Gas production		57,967			72,523			—			—			130,490
Derivative income, net		3,196			—			—			—			3,196
Total operating revenue		127,613			184,899			—			—			312,512
Operating expenses:
Lease operating expenses		19,186			80,090			—			—			99,276
Other operational expense		2,400			—			—			—			2,400
Production taxes		3,296			544			—			—			3,840
Depreciation, depletion, amortization		21,669			95,879			122			—			117,670
Write-down of oil and gas properties		—			340,083			—			—			340,083
Accretion expense		5,129			11,601			23			—			16,753
Salaries, general and administrative		21,411			172			—			—			21,583
Incentive compensation expense		1,417			—			—			—			1,417
Impairment of inventory		6,359			820			—			—			7,179
Total operating expenses		80,867			529,189			145			—			610,201
Income (loss) from operations		46,746			(344,290	)		(145	)		—			(297,689	)
Other (income) expenses:
Interest expense		9,913			41			—			—			9,954
Interest income		(281	)		(1	)		—			—			(282	)
Other (income) expense, net		(1,555	)		40			(310	)		—			(1,825	)
(Income) loss from investment in subsidiary		223,760			(137	)		—			(223,623	)		—
Total other (income) expenses		231,837			(57	)		(310	)		(223,623	)		7,847
Income (loss) before taxes		(185,091	)		(344,233	)		165			223,623			(305,536	)
Provision (benefit) for income taxes:
Current		23			—			—			—			23
Deferred		13,583			(120,471	)		—			—			(106,888	)
Total income taxes		13,606			(120,471	)		—			—			(106,865	)
		(198,697	)		(223,762	)		165			223,623			(198,671	)
Less: Net income attributable to non-controlling interest		—			—			—			27			27
Net income (loss)		($198,697	)		($223,762	)	$	165		$	223,596			($198,698	)

16

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

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	55,703		$	65,865			($250	)		($65,615	)	$	55,703
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		20,826			103,049			543			—			124,418
Accretion expense		3,542			9,449			221			—			13,212
Deferred income tax provision (benefit)		274			35,418			—			—			35,692
Settlement of asset retirement obligations		(960	)		(18,838	)		—			—			(19,798	)
Non-cash stock compensation expense		2,741			—			—			—			2,741
Excess tax benefits		(294	)		—			—			—			(294	)
Non-cash derivative income		(1,818	)		—			—			—			(1,818	)
Early extinguishment of debt		1,820			—			—			—			1,820
Non-cash (income) loss from investment in subsidiary		(65,865	)		250			—			65,615			—
Other non-cash expenses		519			—			—			—			519
Change in current income taxes		(8,725	)		(88	)		—			—			(8,813	)
(Increase) decrease in accounts receivable		149,721			(121,407	)		(814	)		—			27,500
(Increase) decrease in other current assets		(181	)		28			—			—			(153	)
Decrease in inventory		813			123			—			—			936
Increase (decrease) in accounts payable		47			(62	)		—			—			(15	)
Decrease in other current liabilities		(21,209	)		(260	)		—			—			(21,469	)
Other expenses		181			(28	)		—			—			153
Net cash provided by (used in) operating activities		137,135			73,499			(300	)		—			210,334
Cash flows from investing activities:
Investment in oil and gas properties		(92,960	)		(76,939	)		(84	)		—			(169,983	)
Proceeds from sale of oil and gas properties, net of expenses		29,047			680			—			—			29,727
Investment in fixed and other assets		(1,125	)		—			—			—			(1,125	)
Net cash used in investing activities		(65,038	)		(76,259	)		(84	)		—			(141,381	)
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		(9,701	)		—			—			—			(9,701	)
Excess tax benefits		294			—			—			—			294
Net payments for share based compensation		(1,071	)		—			—			—			(1,071	)
Net cash used in financing activities		(60,981	)		—			—			—			(60,981	)
Net increase (decrease) in cash and cash equivalents		11,116			(2,760	)		(384	)		—			7,972
Cash and cash equivalents, beginning of period		64,830			3,963			500			—			69,293
Cash and cash equivalents, end of period	$	75,946		$	1,203		$	116		$	—		$	77,265

17

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
SIX MONTHS ENDED JUNE 30, 2009
(In thousands of dollars)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)		($198,697	)		($223,762	)	$	165		$	223,623			($198,671	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		21,669			95,879			122			—			117,670
Write-down of oil and gas properties		—			340,083			—			—			340,083
Impairment of inventory		6,359			820			—			—			7,179
Accretion expense		5,129			11,601			23			—			16,753
Deferred income tax provision (benefit)		13,583			(120,471	)		—			—			(106,888	)
Settlement of asset retirement obligations		(3,773	)		(24,476	)		—			—			(28,249	)
Non-cash stock compensation expense		3,159			—			—			—			3,159
Non-cash derivative expense		1,902			—			—			—			1,902
Non-cash (income) loss from investment in subsidiary		223,760			(137	)		—			(223,623	)		—
Other non-cash expenses		923			—			—			—			923
Unrecognized proceeds from unwound derivative contracts		71,662			—			—			—			71,662
Change in current income taxes		28,760			1,675			—			—			30,435
(Increase) decrease in accounts receivable		36,362			(19,066	)		797			(455	)		17,638
Decrease in other current assets		237			34			—			—			271
Decrease in inventory		15,422			528			—			—			15,950
Increase (decrease) in accounts payable		(4,899	)		16,977			(681	)		—			11,397
Decrease in other current liabilities		(27,332	)		(433	)		—			—			(27,765	)
Other expenses		66			28			—			—			94
Net cash provided by (used in) operating activities		194,292			79,280			426			(455	)		273,543
Cash flows from investing activities:
Investment in oil and gas properties		(120,964	)		(76,492	)		—			455			(197,001	)
Proceeds from sale of oil and gas properties, net of expenses		5,496			—			—			—			5,496
Sale of fixed assets		—			35			—			—			35
Investment in fixed and other assets		(376	)		—			—			—			(376	)
Acquisition of non-controlling interest in subsidiary		—			(40	)		—			—			(40	)
Net cash provided by (used in) investing activities		(115,844	)		(76,497	)		—			455			(191,886	)
Cash flows from financing activities:
Net proceeds from issuance of common stock		60,456			—			—			—			60,456
Repayment of bank borrowings		(100,000	)		—			—			—			(100,000	)
Deferred financing costs		(175	)		—			—			—			(175	)
Purchase of treasury stock		(347	)		—			—			—			(347	)
Net payments for share based compensation		(389	)		—			—			—			(389	)
Net cash used in financing activities		(40,455	)		—			—			—			(40,455	)
Net increase in cash and cash equivalents		37,993			2,783			426			—			41,202
Cash and cash equivalents, beginning of period		67,122			818			197			—			68,137
Cash and cash equivalents, end of period	$	105,115		$	3,601		$	623		$	—		$	109,339

18

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 June 30, 2010, and the related condensed consolidated statement of operations for the three and six-month periods ended June 30, 2010 and 2009, and the condensed consolidated statement of cash flows for the six-month periods ended June 30, 2010 and 2009. 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, 2009, 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 February 25, 2010, 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, 2009, 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
August 5, 2010

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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;

• 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;

• inflation;

• lack of availability 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 operations;

• 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 this Quarterly Report 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, 2009, or elsewhere in this Quarterly Report on Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

20

     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, 2009.

Overview

     Stone Energy Corporation is 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, which we have targeted as important exploration areas. We are also active in the Appalachia region, where we have established a significant acreage position in the Marcellus Shale. Throughout this document, reference to our “Gulf Coast Basin” properties includes our Gulf Coast onshore, shelf, deep shelf and deep water properties.

     On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon and it sank, leading to the oil spill currently affecting the GOM. In response to this incident, the Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or “BOEMRE”) of the U.S. Department of the Interior issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. Implementation of the moratorium was blocked by a U.S. district court, which was subsequently affirmed on appeal, but on July 12, 2010, the BOEMRE issued a new moratorium that applies to certain deep water drilling operations. The new moratorium will last until November 30, 2010, or until such earlier time that the BOEMRE determines that affected drilling operations can proceed safely. The BOEMRE has imposed numerous new safety requirements on the drilling of new wells in offshore waters and these new requirements have slowed the issuance of permits for new wells in shallow waters not subject to the moratorium. The BOEMRE is also expected to issue new safety and environmental guidelines or regulations for drilling in the Gulf of Mexico and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. Our drilling operations at Amberjack were halted by the moratorium in May 2010 and the second well in our Amberjack drilling program was temporarily abandoned. For the three months ended June 30, 2010, we recorded $1.1 million of charges related to the delay in the drilling of the second well in our Amberjack drilling program. In July 2010, we received approval to resume operations at Amberjack, and we expect to commence drilling the second well in our Amberjack program in August 2010.

     In May 2010, we renewed our insurance policies, which include coverage for general liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, third party liability, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages and losses.

     For more information, please read the discussion in this report under Part II, Item 1A. “Risk Factors.”

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;

• 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.

21

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

     BP/Deepwater Horizon Oil Spill- The recent 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 (see“Item 1A. Risk Factors”). 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 June 30, 2010, we have approximately $285 million of 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 June 30, 2010, the computation of our ceiling test indicated a cushion of approximately $244 million.

     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.

     Reserve Replacement— We have faced challenges in replacing reserves at a reasonable unit cost. Our diversification into the deep water/deep shelf GOM and Appalachia are strategies we are employing to mitigate this trend. Failure to replace reserves at an acceptable unit cost can result in higher unit rates of depreciation, depletion and amortization and ceiling test write-downs.

     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, 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 expense for alleged underpaid franchise taxes in prior years and higher franchise tax expense in future years. See“Item 1. Legal Proceedings.”

Liquidity and Capital Resources

     At August 4, 2010, we had $281.9 million of availability under our bank credit facility and cash on hand of approximately $64.0 million. Our capital expenditure budget for 2010 has been set at $400 million, which we intend to finance primarily with cash flow from operations. 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 2010 cash flow from operations exceeds our estimated 2010 capital expenditures, we may pay down a portion of our existing debt, expand our capital budget, or invest in money markets.

     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 have been introduced in Congress which would require us to demonstrate our capabilities for greater financial responsibility in the event of spills. In addition, we are subject to an annual evaluation for exemption from supplemental bonding on plugging and abandoning obligations. It is possible that the resolution of these uncertainties could cause severe impacts 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 $210.3 million during the six months ended June 30, 2010 compared to $273.5 million in the comparable period in 2009. Net cash flow provided by operating activities during the six months ended June 30, 2009 included $71.7 million of proceeds from the unwinding of derivative contracts. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2010 capital expenditures with cash flow provided by operating activities.

     Net cash flow used in investing activities totaled $141.4 million during the six months ended June 30, 2010, 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 investing activities totaled $191.9 million during the six months ended June 30, 2009, which

22

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 $61.0 million for the six months ended June 30, 2010, which primarily represents repayments of borrowings under our bank credit facility of $125.0 million, the redemption of our 8¹/4% Senior 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 $9.7 million of deferred financing costs. Net cash flow used in financing activities totaled $40.5 million for the six months ended June 30, 2009, which primarily represents repayments of borrowings under our bank credit facility of approximately $100 million net of proceeds from the sale of common stock of approximately $60.5 million.

     We had working capital at June 30, 2010 of $75.1 million.

     Capital Expenditures.During the three months ended June 30, 2010, additions to oil and gas property costs of $70.8 million included $24.8 million of lease and property acquisition costs, $4.1 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $7.2 million of capitalized interest. During the six months ended June 30, 2010, additions to oil and gas property costs of $134.6 million included $50.8 million of lease and property acquisition costs, $9.0 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $13.6 million of capitalized interest. These investments were financed by cash flow from operations.

     Bank Credit Facility.On August 28, 2008, we entered into an amended and restated revolving credit facility totaling $700 million, maturing on July 1, 2011, with a syndicated bank group. In May 2010, our borrowing base was reaffirmed at $395 million. At June 30, 2010, we had $50 million in borrowings under our bank credit facility, letters of credit totaling $63.1 million had been issued pursuant to our bank credit facility, and the weighted average interest rate under our bank credit facility was approximately 2.6%. As of August 4, 2010, we had $50 million of outstanding borrowings under our bank credit facility and letters of credit totaling $63.1 million had been issued pursuant to our bank credit facility, leaving $281.9 million of availability under our bank credit facility. Our bank credit facility is guaranteed by all of our material direct and indirect subsidiaries, including Stone Offshore.

     The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At Stone’s option, loans under the credit facility will bear interest at a rate based on the adjusted London Interbank Offering 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. Stone has been and remains in compliance with all of the financial covenants under our bank credit facility.

     Senior Notes Offering and Redemption of Senior Subordinated Notes.On January 26, 2010, we completed a public offering of $275 million aggregate principal amount of 8⁵/8% Senior Notes due 2017. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $265 million. Approximately $202 million of the net proceeds from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 8¹/4% Senior Subordinated Notes due 2011. The remaining proceeds were used for general corporate purposes, including the repayment of borrowings under our bank credit facility.

     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 June 30, 2010, 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 six months ended June 30, 2010.

23

Results of Operations

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

	Three Months Ended
	June 30,
	2010		2009		Variance			% Change
Production:
Oil (MBbls)		1,430		1,544		(114	)		(7	)%
Natural gas (MMcf)		11,146		9,723		1,423			15	%
Oil and natural gas (MMcfe)		19,726		18,987		739			4	%
Revenue data (in thousands) (a):
Oil revenue	$	103,159	$	107,972	$	(4,813	)		(4	)%
Natural gas revenue		60,823		62,340		(1,517	)		(2	)%
Total oil and natural gas revenue	$	163,982	$	170,312	$	(6,330	)		(4	)%
Average prices (a):
Oil (per Bbl)	$	72.14	$	69.93	$	2.21			3	%
Natural gas (per Mcf)		5.46		6.41		(0.95	)		(15	)%
Oil and natural gas (per Mcfe)		8.31		8.97		(0.66	)		(7	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.87	$	2.17	$	(0.30	)		(14	)%
Salaries, general and administrative expenses (b)		0.51		0.52		(0.01	)		(2	)%
DD&A expense on oil and gas properties		3.16		2.93		0.23			8	%

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

	Six Months Ended
	June 30,
	2010		2009		Variance			% Change
Production:
Oil (MBbls)		2,852		2,838		14			0.5	%
Natural gas (MMcf)		21,744		19,382		2,362			12	%
Oil and natural gas (MMcfe)		38,856		36,410		2,446			7	%
Revenue data (in thousands) (a):
Oil revenue	$	203,724	$	178,826	$	24,898			14	%
Natural gas revenue		124,049		130,490		(6,441	)		(5	)%
Total oil and natural gas revenue	$	327,773	$	309,316	$	18,457			6	%
Average prices (a):
Oil (per Bbl)	$	71.43	$	63.01	$	8.42			13	%
Natural gas (per Mcf)		5.71		6.73		(1.02	)		(15	)%
Oil and natural gas (per Mcfe)		8.44		8.50		(0.06	)		(0.7	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.94	$	2.73	$	(0.79	)		(29	)%
Salaries, general and administrative expenses (b)		0.53		0.59		(0.06	)		(10	)%
DD&A expense on oil and gas properties		3.13		3.15		(0.02	)		(0.6	)%

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

     During the three months ended June 30, 2010, we reported net income totaling $29.1 million, or $0.60 per share, compared to net income for the three months ended June 30, 2009 of $27.2 million, or $0.65 per share. For the six months ended June 30, 2010, we reported net income of $55.7 million, or $1.15 per share. For the six months ended June 30, 2009, we reported a net loss totaling $198.7 million, or $4.92 per share. All per share amounts are on a diluted basis.

     We follow the full cost method of accounting for oil and gas properties. At the end of the first quarter of 2009, we recognized a ceiling test write-down of our oil and gas properties totaling $340.1 million ($221.1 million after taxes). The write-down did not impact our cash flow from operations but did reduce net income and stockholders’ equity.

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

     Production.During the second quarter of 2010, total production volumes increased 4% to 19.7 Bcfe compared to 19.0 Bcfe produced during the second quarter of 2009. Oil production during the second quarter of 2010 totaled approximately 1,430,000 barrels compared to 1,544,000 barrels produced during the second quarter of 2009, while natural gas production totaled

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11.1 Bcf during the second quarter of 2010 compared to 9.7 Bcf produced during the second quarter of 2009. Production deferrals due to hurricanes totaled approximately 4.4 Bcfe for the second quarter of 2009. Without the effects of hurricane production deferrals, production volumes decreased approximately 3.7 Bcfe for the second quarter of 2010 compared to the comparable 2009 quarter as a result of natural production declines.

     Year-to-date 2010 production totaled 2,852,000 barrels of oil and 21.7 Bcf of natural gas compared to 2,838,000 barrels of oil and 19.4 Bcf of natural gas produced during the comparable 2009 period. Production deferrals due to hurricanes for the six months ended June 30, 2009 amounted to 10.7 Bcfe. Without the effects of hurricane production deferrals, year-to-date 2010 production volumes decreased approximately 8.3 Bcfe from year-to-date 2009 production volumes as a result of natural production declines.

     Prices. Prices realized during the second quarter of 2010 averaged $72.14 per Bbl of oil and $5.46 per Mcf of natural gas, or 7% lower, on an Mcfe basis, than second quarter 2009 average realized prices of $69.93 per Bbl of oil and $6.41 per Mcf of natural gas. During the six months ended June 30, 2010, average realized prices were $71.43 per Bbl of oil and $5.71 per Mcf of natural gas, compared to $63.01 per Bbl of oil and $6.73 per Mcf of natural gas for the comparable 2009 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 $0.95 per Mcf and decreased our average realized oil price by $4.02 per Bbl in the second quarter of 2010. During the second quarter of 2009, our effective hedging transactions increased our average realized natural gas price by $2.62 per Mcf and increased our average realized oil price by $12.57 per Bbl. Effective hedging transactions for the six months ended June 30, 2010 increased our average realized natural gas price by $0.75 per Mcf and decreased our average realized oil price by $4.95 per Bbl. During the six months ended June 30, 2009, effective hedging transactions increased our average realized natural gas price by $2.48 per Mcf and increased our average realized oil price by $13.28 per Bbl.

     Income.Oil and natural gas revenue decreased 4% to $164.0 million in the second quarter of 2010 from $170.3 million during the second quarter of 2009. The decrease is attributable to a 7% decrease in average realized prices on a gas equivalent basis partially offset by a 4% increase in oil and natural gas production volumes. Oil and natural gas revenue for the six months ended June 30, 2010 totaled $327.8 million compared to $309.3 million during the comparable 2009 period. The increase was primarily due to a 7% increase in oil and natural gas production volumes.

     Derivative Income/Expense.During the year-to-date periods ended June 30, 2010 and 2009, 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 quarter ended June 30, 2010, totaled $2.2 million, consisting of $1.2 million of cash settlements on the ineffective portion of derivative contracts, plus $1.0 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative expense for the quarter ended June 30, 2009, totaled $0.7 million, consisting of $1.5 million of cash settlements on the ineffective derivative contracts, less $2.2 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative income for the six months ended June 30, 2010 totaled $3.4 million, consisting of $1.6 million of cash settlements on the ineffective portion of the derivative contracts, plus $1.8 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative income for the six months ended June 30, 2009 totaled $3.2 million, consisting of $7.6 million of cash settlements on the ineffective portion of the derivative contracts, less $4.4 million of changes in the fair market value of the ineffective portion of derivative contracts.

     Expenses.Lease operating expenses during the second quarter of 2010 totaled $36.9 million compared to $41.1 million for the second quarter of 2009. For the six months ended June 30, 2010 and 2009, lease operating expenses totaled $75.5 million and $99.3 million, respectively. Lease operating expenses during the first half of 2009 included approximately $16.6 million of repairs in excess of estimated insurance recoveries related to damage from Hurricanes Gustav and Ike. On a unit of production basis, lease operating expenses were $1.94 per Mcfe and $2.73 per Mcfe for the six months ended June 30, 2010 and 2009, respectively.

     The other operational expense charge of $2.4 million for the three and six-month periods ended June 30, 2010 related to a $1.3 million loss on the sale of non-dedicated tubular inventory and $1.1 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. The other operational expense charge of $2.4 million for the three and six-month periods ended June 30, 2009 related to the cancellation of a drilling contract based on declining commodity prices and the economic environment at that time.

     Depreciation, depletion and amortization (“DD&A”) on oil and gas properties for the second quarter of 2010 totaled $62.3 million, or $3.16 per Mcfe, compared to $55.6 million, or $2.93 per Mcfe, during the second quarter of 2009. For the six months ended June 30, 2010 and 2009, DD&A expense totaled $121.4 million and $114.7 million, respectively.

     Accretion expense for the second quarter of 2010 was $6.6 million compared to $8.4 million for the comparable period of 2009. For the six months ended June 30, 2010 and 2009, accretion expense totaled $13.2 million and $16.8 million, respectively. The decrease is primarily due to a decrease in our credit adjusted risk free rate at December 31, 2009.

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     Salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) for the second quarter of 2010 were $10.0 million compared to $9.9 million in the second quarter of 2009. For the six months ended June 30, 2010 and 2009, SG&A totaled $20.4 million and $21.6 million, respectively.

     The impairment of inventory for the second quarter of 2009 totaling $1.3 million related to the write-down of our tubular inventory. For the six months ended June 30, 2009, the impairment charge totaled $7.2 million. This charge was the result of the market value of these tubular goods falling below historical cost. We consider only tubular goods not committed to capital projects to be inventory items.

     Interest expense for the second quarter of 2010 totaled $2.5 million, net of $7.2 million of capitalized interest, compared to interest expense of $4.8 million, net of $6.5 million of capitalized interest, during the second quarter of 2009. For the six months ended June 30, 2010, interest expense totaled $6.6 million, net of capitalized interest of $13.6 million, compared to interest expense of $10.0 million, net of capitalized interest of $12.8 million for the comparable 2009 period. The decrease is primarily the result of a decrease in outstanding borrowings under our bank credit facility and the redemption of our 8¹/4% Senior Subordinated Notes due 2011, partially offset by interest associated with our 8⁵/8% Senior Notes due 2017 which were issued in January 2010.

     We estimate that we have an approximate $5.3 million current federal income tax benefit for the six months ended June 30, 2010, primarily due to a reclassification between current and deferred income tax expense related to a reduction to our previous estimates of liabilities associated with uncertain tax positions. We have a $2.3 million current income tax payable at June 30, 2010.

Recent Accounting Developments

     Fair Value Measurements and Disclosures.Accounting Standards Update (“ASU”) 2010-06 was issued in January 2010 to improve disclosures about fair value measurements by requiring a greater level of disaggregated information, more robust disclosures about valuation techniques and inputs to fair value measurements, information about significant transfers between the three levels in the fair value hierarchy, and separate presentation of information about purchases, sales, issuances, and settlements on a gross basis rather than as one net number. The guidance provided in ASU 2010-06 became effective for us on January 1, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.

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.

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 46% of our estimated 2010 production from estimated proved reserves, 25% of our estimated 2011 production from estimated proved reserves, and 7% of our estimated 2012 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.

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     Since the filing of our Annual Report on Form 10-K for the year ended December 31, 2009, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

     We had long-term debt outstanding of $525 million at June 30, 2010, of which $475 million, or approximately 91%, bears interest at fixed rates. The $475 million of fixed-rate debt is comprised of $275 million of 8 ⁵/₈ % Senior Notes due 2017 and $200 million of 6³/4% Senior Subordinated Notes due 2014. At June 30, 2010, the remaining $50 million of our outstanding long-term debt bears interest at a floating rate and consists of borrowings outstanding under our bank credit facility. At June 30, 2010, the weighted average interest rate under our bank credit facility was approximately 2.6% per annum. 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 June 30, 2010. Based on this evaluation, our principal executive officer and principal financial officer believe:

• 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 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 June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

     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 a subsidiary. 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 years 2007 through 2009 for Stone remain subject to examination.

     Litigation is subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of these matters and are unable to estimate a range of possible losses or any minimum loss from such matters.

     Stone’s Certificate of Incorporation and/or its Restated Bylaws provide, to the extent permissible under the law of the State of Delaware (Stone’s state of incorporation), for indemnification of and advancement of defense costs to Stone’s current and former directors and officers for potential liabilities related to their service to Stone. Stone has purchased directors and officers insurance policies that, under certain circumstances, may provide coverage to Stone and/or its officers and directors for certain losses resulting from securities-related civil liabilities and/or the satisfaction of indemnification and advancement obligations owed to directors and officers. These insurance policies may not cover all costs and liabilities incurred by Stone and its current and former officers and directors in these regulatory and civil proceedings.

     Ad Valorem Tax Suit.In August 2009, Gene P. Bonvillain, in his capacity as Assessor for the Parish of Terrebonne, State of Louisiana, filed civil action No. 90-03540 and other consolidated cases in the United States District Court for the Eastern District of Louisiana against approximately thirty oil and gas companies, including Stone, and their respective chief executive officers for allegedly unpaid ad valorem taxes. The amount originally alleged to be due by Stone for the years 1998 through 2008 was $11.3 million. The defendants were subsequently served and filed motions to dismiss this litigation pursuant to Rule 12(b)(6) of the Federal Rules of Civil Procedure. On March 29, 2010, the trial court judge dismissed plaintiff’s claims without prejudice, with the dismissal to become effective within ten days unless plaintiff filed an amended complaint correcting its deficiencies. On April 8, 2010, plaintiff filed a first amended complaint without naming any of the chief executive officers as defendants and with an amount allegedly due by Stone of “not less than” $3.5 million. Subsequently, defendants filed motions to dismiss this litigation, and the trial court judge granted these motions to dismiss on July 26, 2010.

     Federal Securities Action and Derivatives Actions.Stone has previously disclosed that on or around November 30, 2005, George Porch filed a putative class action in the United States District Court for the Western District of Louisiana (the “Federal Court”) against Stone, David Welch, Kenneth Beer, D. Peter Canty and James Prince purporting to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. Three similar complaints were filed soon thereafter. On March 17, 2006, these purported class actions were consolidated, with El Paso Fireman & Policeman’s Pension Fund designated as lead plaintiff (“Securities Action”). El Paso Fireman & Policeman’s Pension Fund filed a consolidated class action complaint on or about June 14, 2006.

     Stone has also previously disclosed that on or about December 16, 2005, Robert Farer and Priscilla Fisk filed respective complaints in the Federal Court purportedly alleging claims derivatively on behalf of Stone. Similar complaints were filed thereafter in the Federal Court by Joint Pension Fund, Local No. 164, I.B.E.W., and in the 15^th Judicial District Court, Parish of Lafayette, Louisiana (the “State Court”) by Gregory Sakhno. Stone was named as a nominal defendant and David Welch, Kenneth Beer, D. Peter Canty, James Prince, James Stone, John Laborde, Peter Barker, George Christmas, Richard Pattarozzi, David Voelker, Raymond Gary, B.J. Duplantis and Robert Bernhard were named as defendants in these actions. (These actions are collectively referred to as the “Derivative Actions.”)

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     Stone also previously disclosed that the parties in the Securities Action and the parties in the Derivative Actions had reached agreements to settle the respective proceedings and that the parties’ settlement agreements were subject to Federal Court approval. On March 23, 2010, the Federal Court held a settlement fairness hearing to consider the proposed settlements in both the Securities Action and the Derivative Action. During the settlement fairness hearing, the Federal Court approved both proposed settlements. The Federal Court thereafter entered a Final Judgment and Order of Dismissal with Prejudice dismissing the federal Derivative Action, and an Order and Final Judgment dismissing the Securities Action. On or about April 12, 2010, the State Court Derivative Action was dismissed with prejudice by order of the State Court.

Item 1A. Risk Factors

     The following risk factors update the Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2009. Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2009.

     The explosion and sinking of the Deepwater Horizon oil rig in the Gulf of Mexico and the resulting oil spill has increased certain of the risks that we face and could have a material adverse effect on our business.

     On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon and it sank, leading to the oil spill currently affecting the Gulf of Mexico. The explosion and sinking of the Deepwater Horizon oil rig in the Gulf of Mexico and the resulting oil spill has increased certain of the risks we face, including, without limitation, the following:

• imposition of a drilling moratorium or increased governmental regulation of our and our industry’s operations in a number of areas, including financial responsibility, health and safety, environmental, permitting, taxation and equipment specifications;

• increased difficulty in obtaining licenses to drill offshore wells;

• higher royalty rates;

• higher insurance costs or the unavailability of insurance at any cost;

• decreased access to appropriate equipment, personnel and infrastructure in a timely manner; and

• less favorable investor perception of the risk-adjusted benefits of deep water offshore drilling.

     These factors could have a material adverse effect on our business, financial position or future results of operations, including our ability to timely execute our drilling and development plans.

     A drilling moratorium in the Gulf of Mexico, or other regulatory initiatives in response to the current oil spill in the Gulf of Mexico, could have a material adverse effect our business.

     On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon and it sank, leading to the oil spill currently affecting the Gulf of Mexico. In response to this incident, the Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or “BOEMRE”) of the U.S. Department of the Interior issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. Implementation of the moratorium was blocked by a U.S. district court, which was subsequently affirmed on appeal, but on July 12, 2010, the BOEMRE issued a new moratorium that applies to deep water drilling operations that use subsea blowout preventers or surface blowout preventers on floating facilities. Certain exceptions to the moratorium, include, among others, operations necessary to sustain reservoir pressure from producing wells and workover operations. The new moratorium will last until November 30, 2010, or until such earlier time that the BOEMRE determines that affected drilling operations can proceed safely. The BOEMRE has imposed numerous new safety requirements on the drilling of new wells in offshore waters and these new requirements have slowed the issuance of permits for new wells in shallow waters not subject to the moratorium. The BOEMRE is also expected to issue new safety and environmental guidelines or regulations for drilling in the Gulf of Mexico, and potentially in other geographic regions, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. This incident could also result in drilling suspensions or other regulatory initiatives in other areas of the United States and abroad. Although it is difficult to predict the ultimate impact of the moratorium or any new guidelines, regulations or legislation, a prolonged suspension of drilling activity in the Gulf of Mexico and other areas, new regulations and increased liability for companies operating in this sector could reduce drilling and production activity, or increase the costs of our services, or could have a material adverse effect on our business, financial position or future results of operations, including our ability to timely execute our drilling and development plans.

     The Oil Pollution Act of 1990 (the “OPA”) and regulations adopted pursuant to the OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to

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cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. The OPA also currently limits the liability of a responsible party for economic damages, excluding all oil spill response costs, to $75 million, although this limit does not apply if a federal safety, construction or operating regulation was violated. The states in which we operate have also adopted similar laws and regulations relating to offshore operations in their waters. The United States Congress is currently considering a variety of amendments to the OPA in response to the recent Deepwater Horizon incident in the Gulf of Mexico, including an increase in the minimum level of financial responsibility, an elimination of all liability limitations on damages, and enhancements to safety and spill-response requirements. Additional state regulation in these areas is also possible. Any new requirements would likely increase the cost of operations for our offshore activities, including insurance costs, and expose us to increased liability, which could have an adverse effect on our results of operations. In addition, we are subject to an annual evaluation for exemption from supplemental bonding on plugging and abandoning obligations. Any new requirement to post additional bonds or letters of credit could have an adverse effect on our liquidity. If we are unable to satisfy new legislative and regulatory requirements, we may be required to curtail operations, sell our offshore properties or operations, or enter into partnerships with other companies that can meet the new requirements, which may have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether the OPA will be amended or new state regulations adopted, what the substance of any such amendment or regulations will be or what impact any such amendments might have on our operations. In addition, our costs could also increase for our onshore operations due to changes in standard industry practices in anticipation of, or in reaction to, any new offshore regulation.

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

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

     Currently, we have general liability insurance coverage with an annual aggregate limit of up to $75 million applicable to our working interest. We also have an offshore property physical damage policy that contains a $75 million annual aggregate named windstorm limit. Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $10 million to $150 million per occurrence. Exploratory deep water wells have a coverage limit of $300 million per occurrence. Additionally, we maintain $35 million in oil pollution liability coverage. Our control of well and oil pollution liability policy limits are scaled proportionately to our working interests, and all of our policies described above are subject to deductibles, sub-limits and/or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

     An operational or hurricane related event may cause damage or liability in excess of our coverage, which might severely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also severely impact our financial position. For example, we experienced production interruptions in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance.

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

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     The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

     The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

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 second quarter of 2010:

								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:
April 2010		—			—		—
May 2010		—			—		—
June 2010		—			—		—
		—			—		—	$	92,928,632
Other:
April 2010		458	(a)	$	18.20		—
May 2010		469	(a)		15.10		—
June 2010		—			—		—
		927			16.63		—		N/A
Total		927		$	16.63		—

(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	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 Form 8-K, filed January 29, 2010).
4.2	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 Form 8-K, filed January 29, 2010).
4.3	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 Form 8-K, filed January 29, 2010).
*15.1	Letter from Ernst & Young LLP dated August 5, 2010, 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.

*	Filed herewith.
#	Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

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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: August 5, 2010	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	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 Form 8-K, filed January 29, 2010).
4.2	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 Form 8-K, filed January 29, 2010).
4.3	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 Form 8-K, filed January 29, 2010).
*15.1	Letter from Ernst & Young LLP dated August 5, 2010, 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.

*	Filed herewith.
#	Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

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