Edgar Filing: STONE ENERGY CORP

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2010


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

For the transition period from to

Commission file number 1-12074

STONE ENERGY CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		72-1235413 (I.R.S. Employer Identification No.)

625 E. Kaliste Saloom Road Lafayette, Louisiana (Address of Principal Executive Offices)		70508 (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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). Yes o No o

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


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(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). Yes o No þ

As of November 3, 2010, there were 48,531,749 shares of the registrant’s Common Stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS


			Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements:
Condensed Consolidated Balance Sheet as of September 30, 2010 and December 31, 2009			1

Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2010 and 2009			2

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 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			28

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			30

Item 6. Exhibits			31

Signature			32
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)


	September 30,			December 31,
	2010			2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	85,370		$	69,293
Accounts receivable		100,167			118,129
Fair value of hedging contracts		22,538			16,223
Deferred tax asset		14,561			14,571
Inventory		6,939			8,717
Other current assets		1,162			814

Total current assets		230,737			227,747

Oil and gas properties — United States — full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $4,717,734 and $4,536,599, respectively		893,437			856,467
Unevaluated		416,726			329,242
Building and land, net		5,717			5,723
Fair value of hedging contracts		4,462			1,771
Fixed assets, net		4,236			4,084
Other assets, net		20,464			29,208

Total assets	$	1,575,779		$	1,454,242


Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	50,000		$	—
Accounts payable to vendors		66,615			66,863
Undistributed oil and gas proceeds		21,143			15,280
Fair value of hedging contracts		14,104			34,859
Asset retirement obligations		40,892			30,515
Current income tax payable		5,096			11,110
Other current liabilities		68,347			42,983

Total current liabilities		266,197			201,610

Long-term debt		475,000			575,000
Deferred taxes		95,263			44,528
Asset retirement obligations		271,803			265,021
Fair value of hedging contracts		2,651			7,721
Other long-term liabilities		20,730			18,412

Total liabilities		1,131,644			1,112,292


Commitments and contingencies

Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 47,763,216 and 47,509,144 shares, respectively		478			475
Treasury stock (16,582 shares, respectively, at cost)		(860	)		(860	)
Additional paid-in capital		1,329,013			1,324,410
Accumulated deficit		(890,711	)		(966,695	)
Accumulated other comprehensive income (loss)		6,215			(15,380	)

Total stockholders’ equity		444,135			341,950

Total liabilities and stockholders’ equity	$	1,575,779		$	1,454,242

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

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Operating revenue:
Oil production	$	97,688		$	134,737		$	301,412		$	313,563
Gas production		55,522			67,982			179,571			198,472
Derivative income, net		405			—			3,818			3,106

Total operating revenue		153,615			202,719			484,801			515,141


Operating expenses:
Lease operating expenses		36,882			28,136			112,429			127,412
Other operational expense		3,003			—			5,450			2,400
Production taxes		1,517			2,126			4,761			5,966
Depreciation, depletion and amortization		60,482			68,652			184,900			186,322
Write-down of oil and gas properties		—			—			—			340,083
Accretion expense		6,605			8,131			19,817			24,884
Salaries, general and administrative expenses		9,751			9,490			30,199			31,073
Incentive compensation expense		767			1,932			2,113			3,349
Impairment of inventory		—			1,275			—			8,454
Derivative expenses, net		—			91			—			—

Total operating expenses		119,007			119,833			359,669			729,943


Income (loss) from operations		34,608			82,886			125,132			(214,802	)


Other (income) expenses:
Interest expense		2,667			5,170			9,273			15,124
Interest income		(51	)		(155	)		(1,110	)		(437	)
Other income		(1,802	)		(1,017	)		(5,253	)		(3,270	)
Early extinguishment of debt		—			—			1,820			—
Other expense		57			80			534			508

Total other expenses		871			4,078			5,264			11,925


Net income (loss) before income taxes		33,737			78,808			119,868			(226,727	)


Provision (benefit) for income taxes:
Current		10,182			1,615			4,918			1,638
Deferred		3,274			26,140			38,966			(80,748	)

Total income taxes		13,456			27,755			43,884			(79,110	)


Net income (loss)		20,281			51,053			75,984			(147,617	)
Less: Net income attributable to non-controlling interest		—			—			—			27

Net income (loss) attributable to Stone Energy Corporation	$	20,281		$	51,053		$	75,984		$	(147,644	)


Basic income (loss) per share attributable to Stone Energy Corporation stockholders	$	0.42		$	1.06		$	1.57		$	(3.45	)
Diluted income (loss) per share attributable to Stone Energy Corporation stockholders	$	0.42		$	1.06		$	1.57		$	(3.45	)

Average shares outstanding		47,713			47,478			47,659			42,762
Average shares outstanding assuming dilution		47,727			47,490			47,681			42,762

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands of dollars)
(Unaudited)


	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	75,984		$	(147,617	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		184,900			186,322
Write-down of oil and gas properties		—			340,083
Impairment of inventory		—			8,454
Accretion expense		19,817			24,884
Deferred income tax provision (benefit)		38,966			(80,748	)
Settlement of asset retirement obligations		(28,652	)		(61,394	)
Non-cash stock compensation expense		4,023			4,392
Excess tax benefits		(297	)		—
Non-cash derivative (income) expense		(1,459	)		3,451
Early extinguishment of debt		1,820			—
Other non-cash expenses		741			(96	)
Unrecognized proceeds from unwound derivative contracts		—			35,095
Change in current income taxes		(6,014	)		32,050
Decrease in accounts receivable		39,569			49,885
(Increase) decrease in other current assets		(305	)		391
Decrease in inventory		1,778			16,923
Decrease in accounts payable		(1,265	)		(18,516	)
Decrease in other current liabilities		(21,401	)		(20,477	)
Other		1,261			(164	)

Net cash provided by operating activities		309,466			372,918


Cash flows from investing activities:
Investment in oil and gas properties		(261,970	)		(232,209	)
Proceeds from sale of oil and gas properties, net of expenses		31,635			5,571
Sale of fixed assets		—			35
Investment in fixed and other assets		(1,722	)		(1,276	)
Acquisition of non-controlling interest in subsidiary		—			(40	)

Net cash used in investing activities		(232,057	)		(227,919	)


Cash flows from financing activities:
Net proceeds from issuance of common stock		—			60,442
Repayments of bank borrowings		(125,000	)		(175,000	)
Redemption of senior subordinated notes		(200,503	)		—
Proceeds from issuance of senior notes		275,000			—
Deferred financing costs		(9,766	)		(65	)
Excess tax benefits		297			—
Purchase of treasury stock		—			(347	)
Net payments for share based compensation		(1,360	)		(417	)

Net cash used in financing activities		(61,332	)		(115,387	)


Net increase in cash and cash equivalents		16,077			29,612
Cash and cash equivalents, beginning of period		69,293			68,137

Cash and cash equivalents, end of period	$	85,370		$	97,749

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Interim Financial Statements

The condensed consolidated financial statements of Stone Energy Corporation (“Stone”) and its subsidiaries as of September 30, 2010 and for the three and nine-month periods ended September 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 nine-month periods ended September 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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(in thousands, except per share data)
Income (numerator):
Net income (loss)	$	20,281		$	51,053		$	75,984		$	(147,644	)
Net income attributable to participating securities		(329	)		(816	)		(1,234	)		—

Net income (loss) attributable to common stock — basic and diluted	$	19,952		$	50,237		$	74,750		$	(147,644	)


Weighted average shares (denominator):
Weighted average shares — basic		47,713			47,478			47,659			42,762
Diluted effect of stock options and unvested restricted stock		14			12			22			—

Weighted average shares — diluted		47,727			47,490			47,681			42,762


Basic income (loss) per common share	$	0.42		$	1.06		$	1.57		$	(3.45	)

Diluted income (loss) per common share	$	0.42		$	1.06		$	1.57		$	(3.45	)

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 436,000 shares in the three months ended September 30, 2010 and 2009, respectively. 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 shares during the nine months ended September 30, 2010. All outstanding stock options (approximately 501,000 shares) were considered antidilutive during the nine months ended September 30, 2009 because we had a net loss for the period.

During the three months ended September 30, 2010 and 2009, respectively, approximately 59,000 and 8,900 shares of common stock were issued upon the vesting of restricted stock by employees and nonemployee directors. During the nine months ended September 30, 2010 and 2009, respectively, approximately 254,000 and 114,000 shares of common stock were issued upon the vesting of restricted stock by employees and nonemployee directors. During the nine months ended September 30, 2009, 100,000 shares of common stock were repurchased under our stock repurchase program. On June 10, 2009, 8,050,000 shares of common stock were issued in a public offering.

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 the nine-month periods ended September 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.

All of our derivative instruments at September 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 September 30, 2010 and December 31, 2009.


Fair Value of Derivative Instruments at September 30, 2010
(in millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of hedging contracts	$	22.5	Current liabilities: Fair value of hedging contracts	$	(14.1	)
	Long-term assets: Fair value of hedging contracts		4.5	Long-term liabilities: Fair value of hedging contracts		(2.7	)

		$	27.0		$	(16.8	)


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 value of hedging contracts	$	16.2	Current liabilities: Fair value of hedging contracts	$	(34.9	)
	Long-term assets: Fair value of hedging contracts		1.8	Long-term liabilities: Fair value of hedging 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 nine-month periods ended September 30, 2010 and 2009.


The Effect of Derivative Instruments on the Statement of Operations for the Three Months Ended September 30, 2010 and 2009
(in millions)
	Amount of Gain
	(Loss) Recognized
Derivatives in Cash	in OCI on						Gain (Loss) Reclassified from					Gain (Loss) Recognized in Income
Flow Hedging	Derivative						Accumulated OCI into Income					on Derivative
Relationships	(Effective Portion)						(Effective Portion) (a)					(Ineffective Portion)
	2010			2009			Location	2010		2009		Location	2010		2009
Commodity contracts	$	(6.5	)	$	(28.5	)	Operating revenue - oil/gas production	$	6.0	$	46.4	Derivative income (expense), net	$	0.4	$	(0.1	)

Total	$	(6.5	)	$	(28.5	)		$	6.0	$	46.4		$	0.4	$	(0.1	)


(a)		For the three months ended September 30, 2010, effective hedging contracts reduced oil revenue by $3.7 million and increased gas revenue by $9.7 million. For the three months ended September 30, 2009, effective hedging contracts increased oil revenue by $19.0 million and increased gas revenue by $27.4 million.


The Effect of Derivative Instruments on the Statement of Operations for the Nine Months Ended September 30, 2010 and 2009
(in millions)
	Amount of Gain
	(Loss) Recognized
Derivatives in Cash	in OCI on					Gain (Loss) Reclassified from					Gain (Loss) Recognized in Income
Flow Hedging	Derivative					Accumulated OCI into Income					on Derivative
Relationships	(Effective Portion)					(Effective Portion) (a)					(Ineffective Portion)
	2010		2009			Location	2010		2009		Location	2010		2009
Commodity contracts	$	21.6	$	(68.9	)	Operating revenue - oil/gas production	$	8.2	$	132.1	Derivative income, net	$	3.8	$	3.1

Total	$	21.6	$	(68.9	)		$	8.2	$	132.1		$	3.8	$	3.1


(a)		For the nine months ended September 30, 2010, effective hedging contracts reduced oil revenue by $17.8 million and increased gas revenue by $26.0 million. For the nine months ended September 30, 2009, effective hedging contracts increased oil revenue by $56.7 million and increased gas revenue by $75.4 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.

At September 30, 2010, we had accumulated other comprehensive income of $6.2 million, net of tax, which related to the fair value of our 2010, 2011 and 2012 swap contracts. We believe that approximately $5.2 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 November 3, 2010:


	Fixed-Price Swaps
	Natural Gas				Oil
	Daily Volume		Swap		Daily Volume			Swap
	(MMBtus/d)		Price		(Bbls/d)			Price
2010		30,000	$	6.50		1,000		$	60.20
2010		20,000		6.97		2,000			63.00
2010						1,000			64.05
2010						1,000			75.00
2010						1,000			75.25
2010						2,000	(a)		80.10
2010						1,000	(b)		84.35

2011		20,000		5.20		1,000			70.05
2011		10,000		6.83		1,000			78.20
2011						1,000			80.20
2011						1,000			83.00
2011						1,000			83.05
2011						1,000	(c)		85.20
2011						1,000			85.25

2012						1,000			90.30
2012						1,000			90.45


(a)		April — December

(b)		July — December

(c)		January — June

Note 4 – Long-Term Debt

Long-term debt consisted of the following at:


	September 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 debt		525.0		575.0
Less: Current portion of long-term debt		50.0		—

Total long-term debt	$	475.0	$	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. At September 30, 2010, we had $50 million of outstanding 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 2.5%. Our borrowing base under our bank credit facility was reaffirmed at $395 million on October 29, 2010. As of November 3, 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 our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

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.

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 September 30, 2010, $4.0 million had been accrued in connection with the February 1, 2011 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 nine-month periods ended September 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010		2009
	(in millions)
Net income (loss)	$	20.3		$	51.1		$	76.0	$	(147.6	)
Other comprehensive income (loss), net of tax effect:
Adjustment for fair value accounting of derivatives		(6.5	)		(28.5	)		21.6		(68.9	)

Comprehensive income (loss) attributable to Stone Energy Corporation	$	13.8		$	22.6		$	97.6	$	(216.5	)

Note 6 – Asset Retirement Obligations

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


	Nine Months
	Ended
	September 30,
	2010
	(in millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	295.5
Revision of estimates		26.1
Liabilities settled		(28.7	)
Accretion expense		19.8

Asset retirement obligations as of the end of the period, including current portion	$	312.7

In October 2010, we received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) indicating that certain identified wells and facilities operated by us will need to be retired on a timing schedule, which was accelerated from the timing estimated in calculating liabilities for asset retirement obligations. The BOEMRE has requested that we submit an abandonment plan by February 2011 for the identified wells and facilities after which the BOEMRE will issue a final order. In the third quarter of 2010, we increased our asset retirement obligations in the amount of $26.1 million for the estimated impact of the accelerated timing of the retirement of these assets. The final order will ultimately determine the impact on our asset retirement obligations and could result in an additional upward or downward revision.

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 nine months ended September 30, 2009, we recorded a write-down of our tubular inventory in the amount of $8.5 million. This charge was the result of the market value of these tubulars falling below historical cost.

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 September 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, see Note 3 — Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in money market funds, 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 September 30, 2010
			Quoted Prices		Significant
			in Active		Other		Significant
			Markets for		Observable		Unobservable
			Identical Assets		Inputs		Inputs
Assets	Total		(Level 1)		(Level 2)		(Level 3)
	(in millions)
Money market funds	$	7.2	$	7.2	$	—	$	—
Hedging contracts		27.0		—		27.0		—

Total	$	34.2	$	7.2	$	27.0	$	—


	Fair Value Measurements at September 30, 2010
				Quoted Prices
				in Active		Significant
				Markets for		Other			Significant
				Identical		Observable			Unobservable
				Liabilities		Inputs			Inputs
Liabilities	Total			(Level 1)		(Level 2)			(Level 3)
	(in millions)
Hedging contracts	$	(16.8	)	$	—	$	(16.8	)	$	—

Total	$	(16.8	)	$	—	$	(16.8	)	$	—

The fair value of cash and cash equivalents, accounts receivable, accounts payable to vendors and our variable-rate bank debt approximated book value at September 30, 2010 and December 31, 2009. As of September 30, 2010, the fair value of our $275 million 8⁵/₈% Senior Notes due 2017 was approximately $269.5 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 September 30, 2010 and December 31, 2009, the fair value of our $200 million 6³/4% Senior Subordinated Notes due 2014 was approximately $185 million and $178 million, respectively. The fair values of our outstanding notes were determined based upon quotes obtained from brokers.

Note 9 – Acquisitions and Divestitures

Included in other current liabilities at September 30, 2010, is a $52.6 million accrual for amounts due related to lease acreage acquisitions from various landowners in Appalachia, which represents a non-cash investing activity for purposes of the statement of cash flows.

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 plus estimated accrued interest amount to approximately $20.4 million. The franchise tax years 2007 through 2009 for Stone remain subject to examination, which potentially exposes us to additional estimated assessments of $7.2 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. Defendants filed motions to dismiss this litigation, and the trial court judge granted these motions to dismiss on July 26, 2010. Subsequently, Bonvillain appealed the dismissal, and the appeal is currently pending before the 5^th Circuit Court of Appeals.

Note 11 — Income Taxes

The following is a reconciliation of unrecognized tax benefits for the nine months ended September 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		0.9
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 September 30, 2010	$	0.9

We had a net benefit of $0.3 million in the current period as a result of net amounts recognized that impacted our effective rate. In addition, we recognized a $1.1 million net credit to interest expense associated with additions and reductions to unrecognized tax benefits. The entire balance of unrecognized tax benefits at September 30, 2010 would impact our tax rate if recognized.

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 September 30, 2010 and December 31, 2009 and for the three and nine-month periods ended September 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)
SEPTEMBER 30, 2010
(In thousands of dollars)


							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	83,632		$	1,556		$	182		$	—		$	85,370
Accounts receivable		49,162			373,802			691			(323,488	)		100,167
Fair value of hedging contracts		22,538			—			—			—			22,538
Deferred tax asset		14,561			—			—			—			14,561
Inventory		6,642			297			—			—			6,939
Other current assets		1,147			15			—			—			1,162

Total current assets		177,682			375,670			873			(323,488	)		230,737
Oil and gas properties — United States Proved, net		127,809			760,969			4,659			—			893,437
Unevaluated		340,325			76,401			—			—			416,726
Building and land, net		5,717			—			—			—			5,717
Fair value of hedging contracts		4,462			—			—			—			4,462
Fixed assets, net		4,236			—			—			—			4,236
Other assets, net		20,464			—			—			—			20,464
Investment in subsidiary		835,370			581			—			(835,951	)		—

Total assets	$	1,516,065		$	1,213,621		$	5,532		$	(1,159,439	)	$	1,575,779


Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	50,000		$	—		$	—		$	—		$	50,000
Accounts payable to vendors		359,267			30,830			6			(323,488	)		66,615
Undistributed oil and gas proceeds		20,693			450			—			—			21,143
Fair value of hedging contracts		14,104			—			—			—			14,104
Asset retirement obligations		—			40,892			—			—			40,892
Current income tax payable		5,096			—			—			—			5,096
Other current liabilities		67,816			531			—			—			68,347

Total current liabilities		516,976			72,703			6			(323,488	)		266,197
Long-term debt		475,000			—			—			—			475,000
Deferred taxes *		(20,415	)		115,678			—			—			95,263
Asset retirement obligations		83,700			183,159			4,944			—			271,803
Fair value of hedging contracts		2,651			—			—			—			2,651
Other long-term liabilities		14,018			6,712			—			—			20,730

Total liabilities		1,071,930			378,252			4,950			(323,488	)		1,131,644


Commitments and contingencies

Stockholders’ equity:
Common stock		478			—			—			—			478
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,329,013			2,125,517			1,639			(2,127,156	)		1,329,013
Accumulated earnings (deficit)		(890,711	)		(1,290,148	)		(1,057	)		1,291,205			(890,711	)
Accumulated other comprehensive income		6,215			—			—			—			6,215

Total stockholders’ equity		444,135			835,369			582			(835,951	)		444,135

Total liabilities and stockholders’ equity	$	1,516,065		$	1,213,621		$	5,532		$	(1,159,439	)	$	1,575,779


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

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
Accumulated 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.

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


							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	16,653		$	81,035		$	—		$	—		$	97,688
Gas production		14,742			40,780			—			—			55,522
Derivative income, net		405			—			—			—			405

Total operating revenue		31,800			121,815			—			—			153,615


Operating expenses:
Lease operating expenses		19,865			17,017			—			—			36,882
Other operational expense		698			2,305			—			—			3,003
Production taxes		1,172			345			—			—			1,517
Depreciation, depletion, amortization		10,824			49,418			240			—			60,482
Accretion expense		1,769			4,725			111			—			6,605
Salaries, general and administrative		9,742			8			1			—			9,751
Incentive compensation expense		767			—			—			—			767

Total operating expenses		44,837			73,818			352			—			119,007


Income (loss) from operations		(13,037	)		47,997			(352	)		—			34,608


Other (income) expenses:
Interest expense		2,654			13			—			—			2,667
Interest income		(49	)		(2	)		—			—			(51	)
Other (income) expense, net		(1,436	)		(16	)		(293	)		—			(1,745	)
(Income) loss from investment in subsidiary		(29,671	)		59			—			29,612			—

Total other (income) expenses		(28,502	)		54			(293	)		29,612			871


Income (loss) before taxes		15,465			47,943			(59	)		(29,612	)		33,737


Provision (benefit) for income taxes:
Current		10,182			—			—			—			10,182
Deferred		(14,998	)		18,272			—			—			3,274

Total income taxes		(4,816	)		18,272			—			—			13,456

Net income (loss)	$	20,281		$	29,671		$	(59	)	$	(29,612	)	$	20,281

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


							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	40,212		$	94,525		$	—		$	—		$	134,737
Gas production		31,952			36,030			—			—			67,982

Total operating revenue		72,164			130,555			—			—			202,719


Operating expenses:
Lease operating expenses		9,401			18,735			—			—			28,136
Production taxes		1,432			694			—			—			2,126
Depreciation, depletion, amortization		11,515			57,059			78			—			68,652
Accretion expense		2,319			5,801			11			—			8,131
Salaries, general and administrative		9,480			9			1			—			9,490
Incentive compensation expense		1,932			—			—			—			1,932
Impairment of inventory		1,055			220			—			—			1,275
Derivative expense, net		91			—			—			—			91

Total operating expenses		37,225			82,518			90			—			119,833


Income (loss) from operations		34,939			48,037			(90	)		—			82,886


Other (income) expenses:
Interest expense		5,149			21			—			—			5,170
Interest income		(149	)		(6	)		—			—			(155	)
Other (income) expense, net		(813	)		25			(149	)		—			(937	)
(Income) loss from investment in subsidiary		(31,234	)		(60	)		—			31,294			—

Total other (income) expenses		(27,047	)		(20	)		(149	)		31,294			4,078


Income (loss) before taxes		61,986			48,057			59			(31,294	)		78,808


Provision for income taxes:
Current		1,615			—			—			—			1,615
Deferred		9,319			16,821			—			—			26,140

Total income taxes		10,934			16,821			—			—			27,755

Net income (loss)	$	51,052		$	31,236		$	59		$	(31,294	)	$	51,053

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


							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	41,262		$	260,150		$	—		$	—		$	301,412
Gas production		44,166			135,405			—			—			179,571
Derivative income, net		3,818			—			—			—			3,818

Total operating revenue		89,246			395,555			—			—			484,801


Operating expenses:
Lease operating expenses		37,061			75,368			—			—			112,429
Other operational expense		1,973			3,477			—			—			5,450
Production taxes		3,481			1,280			—			—			4,761
Depreciation, depletion, amortization		31,650			152,467			783			—			184,900
Accretion expense		5,311			14,174			332			—			19,817
Salaries, general and administrative		30,184			14			1			—			30,199
Incentive compensation expense		2,113			—			—			—			2,113

Total operating expenses		111,773			246,780			1,116			—			359,669


Income (loss) from operations		(22,527	)		148,775			(1,116	)		—			125,132


Other (income) expenses:
Interest expense		9,283			(10	)		—			—			9,273
Interest income		(1,106	)		(4	)		—			—			(1,110	)
Other (income) expense, net		(3,254	)		(658	)		(807	)		—			(4,719	)
Early extinguishment of debt		1,820			—			—			—			1,820
(Income) loss from investment in subsidiary		(95,536	)		309			—			95,227			—

Total other (income) expenses		(88,793	)		(363	)		(807	)		95,227			5,264


Income (loss) before taxes		66,266			149,138			(309	)		(95,227	)		119,868


Provision (benefit) for income taxes:
Current		5,006			(88	)		—			—			4,918
Deferred		(14,724	)		53,690			—			—			38,966

Total income taxes		(9,718	)		53,602			—			—			43,884

Net income (loss)	$	75,984		$	95,536		$	(309	)	$	(95,227	)	$	75,984

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


				Guarantor			Non- Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	106,662		$	206,901		$	—		$	—		$	313,563
Gas production		89,919			108,553			—			—			198,472
Derivative income, net		3,106			—			—			—			3,106

Total operating revenue		199,687			315,454			—			—			515,141


Operating expenses:
Lease operating expenses		28,587			98,825			—			—			127,412
Other operational expense		2,400			—			—			—			2,400
Production taxes		4,728			1,238			—			—			5,966
Depreciation, depletion, amortization		33,184			152,938			200			—			186,322
Write-down of oil and gas properties		—			340,083			—			—			340,083
Accretion expense		7,448			17,402			34			—			24,884
Salaries, general and administrative		30,891			181			1			—			31,073
Incentive compensation expense		3,349			—			—			—			3,349
Impairment of inventory		7,414			1,040			—			—			8,454

Total operating expenses		118,001			611,707			235			—			729,943


Income (loss) from operations		81,686			(296,253	)		(235	)		—			(214,802	)


Other (income) expenses:
Interest expense		15,062			62			—			—			15,124
Interest income		(430	)		(7	)		—			—			(437	)
Other (income) expense, net		(2,368	)		65			(459	)		—			(2,762	)
(Income) loss from investment in subsidiary		192,526			(197	)		—			(192,329	)		—

Total other (income) expenses		204,790			(77	)		(459	)		(192,329	)		11,925


Income (loss) before taxes		(123,104	)		(296,176	)		224			192,329			(226,727	)


Provision (benefit) for income taxes:
Current		1,638			—			—			—			1,638
Deferred		22,902			(103,650	)		—			—			(80,748	)

Total income taxes		24,540			(103,650	)		—			—			(79,110	)


Net income (loss)		(147,644	)		(192,526	)		224			192,329			(147,617	)
Less: Net income attributable to non-controlling interest		—			—			—			27			27

Net income (loss) attributable to Stone Energy Corporation	$	(147,644	)	$	(192,526	)	$	224		$	192,302		$	(147,644	)

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


				Guarantor			Non- Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	75,984		$	95,536			($309	)		($95,227	)	$	75,984
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		31,650			152,467			783			—			184,900
Accretion expense		5,311			14,174			332			—			19,817
Deferred income tax provision (benefit)		(14,724	)		53,690			—			—			38,966
Settlement of asset retirement obligations		(5,012	)		(23,640	)		—			—			(28,652	)
Non-cash stock compensation expense		4,023			—			—			—			4,023
Excess tax benefits		(297	)		—			—			—			(297	)
Non-cash derivative income		(1,459	)		—			—			—			(1,459	)
Early extinguishment of debt		1,820			—			—			—			1,820
Non-cash (income) loss from investment in subsidiary		(95,536	)		309			—			95,227			—
Other non-cash expenses		741			—			—			—			741
Change in current income taxes		(5,926	)		(88	)		—			—			(6,014	)
(Increase) decrease in accounts receivable		231,945			(191,343	)		(1,033	)		—			39,569
(Increase) decrease in other current assets		(361	)		56			—			—			(305	)
Decrease in inventory		1,503			275			—			—			1,778
Decrease in accounts payable		(959	)		(306	)		—			—			(1,265	)
Decrease in other current liabilities		(21,171	)		(230	)		—			—			(21,401	)
Other expenses		561			700			—			—			1,261

Net cash provided by (used in) operating activities		208,093			101,600			(227	)		—			309,466


Cash flows from investing activities:
Investment in oil and gas properties		(157,192	)		(104,687	)		(91	)		—			(261,970	)
Proceeds from sale of oil and gas properties, net of expenses		30,955			680			—			—			31,635
Investment in fixed and other assets		(1,722	)		—			—			—			(1,722	)

Net cash used in investing activities		(127,959	)		(104,007	)		(91	)		—			(232,057	)


Cash flows from financing activities:
Repayment of bank borrowings		(125,000	)		—			—			—			(125,000	)
Redemption of senior subordinated notes		(200,503	)		—			—			—			(200,503	)
Proceeds from issuance of senior notes		275,000			—			—			—			275,000
Deferred financing costs		(9,766	)		—			—			—			(9,766	)
Excess tax benefits		297			—			—			—			297
Net payments for share based compensation		(1,360	)		—			—			—			(1,360	)

Net cash used in financing activities		(61,332	)		—			—			—			(61,332	)


Net increase (decrease) in cash and cash equivalents		18,802			(2,407	)		(318	)		—			16,077
Cash and cash equivalents, beginning of period		64,830			3,963			500			—			69,293

Cash and cash equivalents, end of period	$	83,632		$	1,556		$	182		$	—		$	85,370

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


							Non-
				Guarantor			Guarantor
	Parent			Subsidiary			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(147,644	)	$	(192,526	)	$	224		$	192,329		$	(147,617	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		33,184			152,938			200			—			186,322
Write-down of oil and gas properties		—			340,083			—			—			340,083
Impairment of inventory		7,414			1,040			—			—			8,454
Accretion expense		7,448			17,402			34			—			24,884
Deferred income tax provision (benefit)		22,902			(103,650	)		—			—			(80,748	)
Settlement of asset retirement obligations		(6,138	)		(55,256	)		—			—			(61,394	)
Non-cash stock compensation expense		4,392			—			—			—			4,392
Non-cash derivative expense		3,451			—			—			—			3,451
Non-cash (income) loss from investment in subsidiary		192,526			(197	)		—			(192,329	)		—
Other non-cash expenses		(96	)		—			—			—			(96	)
Unrecognized proceeds from unwound derivative contracts		35,095			—			—			—			35,095
Change in current income taxes		30,374			1,676			—			—			32,050
(Increase) decrease in accounts receivable		100,980			(50,903	)		263			(455	)		49,885
Decrease in other current assets		349			42			—			—			391
Decrease in inventory		16,129			794			—			—			16,923
Increase (decrease) in accounts payable		(20,668	)		2,867			(715	)		—			(18,516	)
Decrease in other current liabilities		(19,519	)		(958	)		—			—			(20,477	)
Other expenses		(191	)		27			—			—			(164	)

Net cash provided by (used in) operating activities		259,988			113,379			6			(455	)		372,918


Cash flows from investing activities:
Investment in oil and gas properties		(132,681	)		(99,983	)		—			455			(232,209	)
Proceeds from sale of oil and gas properties, net of expenses		5,571			—			—			—			5,571
Sale of fixed assets		—			35			—			—			35
Investment in fixed and other assets		(1,276	)		—			—			—			(1,276	)
Acquisition of non-controlling interest in subsidiary		—			(40	)		—			—			(40	)

Net cash provided by (used in) investing activities		(128,386	)		(99,988	)		—			455			(227,919	)


Cash flows from financing activities:
Net proceeds from issuance of common stock		60,442			—			—			—			60,442
Repayment of bank borrowings		(175,000	)		—			—			—			(175,000	)
Deferred financing costs		(65	)		—			—			—			(65	)
Purchase of treasury stock		(347	)		—			—			—			(347	)
Net payments for share based compensation		(417	)		—			—			—			(417	)

Net cash used in financing activities		(115,387	)		—			—			—			(115,387	)


Net increase in cash and cash equivalents		16,215			13,391			6			—			29,612
Cash and cash equivalents, beginning of period		67,122			818			197			—			68,137

Cash and cash equivalents, end of period	$	83,337		$	14,209		$	203		$	—		$	97,749

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:

We have reviewed the condensed consolidated balance sheet of Stone Energy Corporation as of September 30, 2010, and the related condensed consolidated statement of operations for the three and nine-month periods ended September 30, 2010 and 2009, and the condensed consolidated statement of cash flows for the nine-month periods ended September 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
November 4, 2010

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

Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.

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

	•		any expected results or benefits associated with our acquisitions;

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

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

	•		our outlook on oil and gas prices;

	•		estimates of our oil and gas reserves;

	•		any estimates of future earnings growth;

	•		the impact of political and regulatory developments;

	•		our outlook on the resolution of pending litigation and government inquiry;

	•		estimates of the impact of new accounting pronouncements on earnings in future periods;

	•		our future financial condition or results of operations and our future revenues and expenses;

	•		our access to capital and our anticipated liquidity;

	•		estimates of future income taxes; and

	•		our business strategy and other plans and objectives for future operations.

We caution you that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:

	•		commodity price volatility;

	•		domestic and worldwide economic conditions;

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

	•		our level of indebtedness;

	•		declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and ceiling test write-downs and impairments;

	•		our ability to replace and sustain production;

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

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

	•		third party interruption of sales to market;

	•		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 and Appalachian 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 our Quarterly Reports on Form 10-Q.

Should one or more of the risks or uncertainties described above, in our Annual Report on Form 10-K for the year ended December 31, 2009, or in our Quarterly Reports on Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this 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.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE,” formerly the Minerals Management Service) of the U.S. Department of the Interior issued a “Notice to Lessees” (“NTL”) on May 30, 2010, and a revised notice on July 12, 2010, implementing a moratorium on deepwater drilling activities that effectively halted deepwater drilling of wells. While the moratorium was in place, the BOEMRE issued a series of NTLs and adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future. The moratorium was lifted on October 12, 2010, but offshore operators must now comply with strict new safety and operating requirements.

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.

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 and Part II, Item 1A, of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 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 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 September 30, 2010, we have approximately $256 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 September 30, 2010, the computation of our ceiling test indicated a cushion of approximately $242.3 million.

Asset Retirement Obligations — In October 2010, we received notification from the BOEMRE indicating that certain identified wells and facilities operated by us will need to be retired on a timing schedule which was accelerated from the timing estimated in calculating liabilities for asset retirement obligations. The BOEMRE has requested that we submit an abandonment plan by February 2011 for the identified wells and facilities after which the BOEMRE will issue a final order. In the third quarter of 2010, we increased our asset retirement obligations in the amount of $26.1 million for the estimated impact of the accelerated timing of the retirement of these assets. The final order will ultimately determine the impact on our asset retirement obligations and could result in an additional upward or downward revision. See “Item 1A. Risk Factors”.

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. Failure to replace reserves can also result in a net reduction in production volumes.

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 November 3, 2010, we had $281.9 million of availability under our bank credit facility and cash on hand of approximately $92.7 million. Our capital expenditure budget for 2010 has been increased to $425 million, which includes specific Appalachian lease acreage acquisitions, but excludes material acquisitions and capitalized interest and general administrative expenses. We intend to finance our capital expenditure budget primarily with cash flow from operations and borrowings under our bank credit facility. 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 $309.5 million during the nine months ended September 30, 2010 compared to $372.9 million in the comparable period in 2009. Net cash flow provided by operating activities during the nine months ended September 30, 2009 included $35.1 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 and borrowings under our bank credit facility.

Net cash flow used in investing activities totaled $232.1 million during the nine months ended September 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 $227.9 million during the nine months ended September 30, 2009, which primarily represents our investment in oil and natural gas properties offset by proceeds from the sale of oil and natural gas properties.

Net cash flow used in financing activities totaled $61.3 million for the nine months ended September 30, 2010, which primarily represents repayments of borrowings under our bank credit facility of $125.0 million, the redemption of our 8¹/4% Senior 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 $275.0 million less $9.8 million of deferred financing costs. Net cash flow used in financing activities totaled $115.4 million for the nine months ended September 30, 2009, which primarily represents repayments of borrowings under our bank credit facility of approximately $175.0 million net of proceeds from the sale of common stock of approximately $60.4 million.

We had a working capital deficit at September 30, 2010 of $35.5 million primarily due to the classification of our outstanding borrowings of $50.0 million under our bank credit facility as current.

Capital Expenditures. During the three months ended September 30, 2010, additions to oil and gas property costs of $171.0 million included $64.2 million of lease and property acquisition costs, $4.4 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $8.0 million of capitalized interest. During the nine months ended September 30, 2010, additions to oil and gas property costs of $305.6 million included $115.0 million of lease and property acquisition costs, $13.4 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $21.6 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. We are currently exploring alternatives for an extension or renegotiation of our bank credit facility which would extend the due date. At September 30, 2010, we had $50 million of outstanding 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 2.5%. On October 29, 2010, our borrowing base was reaffirmed at $395 million. As of November 3, 2010, we had $281.9 million of availability under our bank credit facility. Our bank credit facility is guaranteed by our only material subsidiary, Stone Offshore.

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At 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 September 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 nine months ended September 30, 2010.

Results of Operations

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


	Three Months Ended
	September 30,
	2010		2009		Variance			% Change
Production:
Oil (MBbls)		1,347		1,741		(394	)		(23	%)
Natural gas (MMcf)		10,130		11,517		(1,387	)		(12	%)
Oil and natural gas (MMcfe)		18,212		21,963		(3,751	)		(17	%)
Revenue data (in thousands) (a):
Oil revenue	$	97,688	$	134,737	$	(37,049	)		(28	%)
Natural gas revenue		55,522		67,982		(12,460	)		(18	%)

Total oil and natural gas revenue	$	153,210	$	202,719	$	(49,509	)		(24	%)
Average prices (a):
Oil (per Bbl)	$	72.52	$	77.39	$	(4.87	)		(6	%)
Natural gas (per Mcf)		5.48		5.90		(0.42	)		(7	%)
Oil and natural gas (per Mcfe)		8.41		9.23		(0.82	)		(9	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.03	$	1.28	$	0.75			59	%
Salaries, general and administrative expenses (b)		0.54		0.43		0.11			26	%
DD&A expense on oil and gas properties		3.24		3.06		0.18			6	%


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

(b)		Exclusive of incentive compensation expense.


	Nine Months Ended
	September 30,
	2010		2009		Variance			% Change
Production:
Oil (MBbls)		4,199		4,579		(380	)		(8	%)
Natural gas (MMcf)		31,874		30,899		975			3	%
Oil and natural gas (MMcfe)		57,068		58,373		(1,305	)		(2	%)
Revenue data (in thousands) (a):
Oil revenue	$	301,412	$	313,563	$	(12,151	)		(4	%)
Natural gas revenue		179,571		198,472		(18,901	)		(10	%)

Total oil and natural gas revenue	$	480,983	$	512,035	$	(31,052	)		(6	%)
Average prices (a):
Oil (per Bbl)	$	71.78	$	68.48	$	3.30			5	%
Natural gas (per Mcf)		5.63		6.42		(0.79	)		(12	%)
Oil and natural gas (per Mcfe)		8.43		8.77		(0.34	)		(4	%)
Expenses (per Mcfe):
Lease operating expenses	$	1.97	$	2.18	$	(0.21	)		(10	%)
Salaries, general and administrative expenses (b)		0.53		0.53		—			—
DD&A expense on oil and gas properties		3.16		3.12		0.04			1	%


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

(b)		Exclusive of incentive compensation expense.

During the three months ended September 30, 2010, we reported net income totaling $20.3 million, or $0.42 per share, compared to net income for the three months ended September 30, 2009 of $51.1 million, or $1.06 per share. For the nine months ended September 30, 2010, we reported net income of $76.0 million, or $1.57 per share. For the nine months ended September 30, 2009, we reported a net loss totaling $147.6 million, or $3.45 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 nine-month periods’ results was also due to the following components:

Production. During the three months ended September 30, 2010, total production volumes decreased 17% to 18.2 Bcfe compared to 22.0 Bcfe produced during the comparable 2009 period. Oil production during the three months ended September 30, 2010 totaled approximately 1,347,000 barrels compared to 1,741,000 barrels produced during the three months ended September, 2009, while natural gas production totaled 10.1 Bcf during the three months ended September 30, 2010 compared to

11.5 Bcf produced during the comparable period of 2009. Production deferrals due to hurricanes totaled approximately 1.1 Bcfe for the three months ended September 30, 2009. Without the effects of hurricane production deferrals, production volumes decreased approximately 4.9 Bcfe for the three months ended September 30, 2010 compared to the comparable 2009 period as a result of natural production declines in the GOM.

Production volumes for the nine months ended September 30, 2010 totaled 4,199,000 barrels of oil and 31.9 Bcf of natural gas compared to 4,579,000 barrels of oil and 30.9 Bcf of natural gas produced during the comparable 2009 period. Production deferrals due to hurricanes for the nine months ended September 30, 2009 amounted to 11.8 Bcfe. Without the effects of hurricane production deferrals, year-to-date 2010 production volumes decreased approximately 13.1 Bcfe from year-to-date 2009 production volumes as a result of natural production declines in the GOM.

Prices. Prices realized during the three months ended September 30, 2010 averaged $72.52 per Bbl of oil and $5.48 per Mcf of natural gas, or 9% lower, on an Mcfe basis, than average realized prices of $77.39 per Bbl of oil and $5.90 per Mcf of natural gas during the comparable 2009 period. During the nine months ended September 30, 2010, average realized prices were $71.78 per Bbl of oil and $5.63 per Mcf of natural gas, compared to $68.48 per Bbl of oil and $6.42 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 $0.96 per Mcf and decreased our average realized oil price by $2.79 per Bbl during the three months ended September 30, 2010. During the three months ended September 30, 2009, our effective hedging transactions increased our average realized natural gas price by $2.37 per Mcf and increased our average realized oil price by $10.92 per Bbl. Effective hedging transactions for the nine months ended September 30, 2010 increased our average realized natural gas price by $0.82 per Mcf and decreased our average realized oil price by $4.25 per Bbl. During the nine months ended September 30, 2009, effective hedging transactions increased our average realized natural gas price by $2.44 per Mcf and increased our average realized oil price by $12.39 per Bbl.

Income. Oil and natural gas revenue was $153.2 million during the three months ended September 30, 2010, compared to $202.7 million during the comparable period of 2009. The decrease is attributable to a 9% decrease in average realized prices on a gas equivalent basis along with a 17% decrease in oil and natural gas production volumes. Oil and natural gas revenue for the nine months ended September 30, 2010 totaled $481.0 million compared to $512.0 million during the comparable 2009 period. The decrease was primarily due to a 4% decrease in average realized prices on a gas equivalent basis along with a 2% decrease in oil and natural gas production volumes.

Derivative Income/Expense. During the year-to-date periods ended September 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 three months ended September 30, 2010, totaled $0.4 million, consisting of $0.8 million of cash settlements on the ineffective portion of derivative contracts, less $0.4 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative expense for the three months ended September 30, 2009, totaled $0.1 million, consisting of $0.2 million of cash settlements on the ineffective derivative contracts, less $0.3 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative income for the nine months ended September 30, 2010 totaled $3.8 million, consisting of $2.4 million of cash settlements on the ineffective portion of the derivative contracts, plus $1.4 million of changes in the fair market value of the ineffective portion of derivative contracts. Net derivative income for the nine months ended September 30, 2009 totaled $3.1 million, consisting of $7.8 million of cash settlements on the ineffective portion of the derivative contracts, less $4.7 million of changes in the fair market value of the ineffective portion of derivative contracts.

Expenses. Lease operating expenses during the three months ended September 30, 2010 and 2009 totaled $36.9 million and $28.1 million, respectively. The three months ended September 30, 2009 included approximately $12 million in downward adjustments of previously accrued major maintenance and base lease operating costs as a result of actual costs being less than the previously accrued estimated amounts. For the nine months ended September 30, 2010 and 2009, lease operating expenses totaled $112.4 million and $127.4 million, respectively. Lease operating expenses during the nine months ended September 30, 2009 included approximately $9.5 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 $1.97 per Mcfe and $2.18 per Mcfe for the nine months ended September 30, 2010 and 2009, respectively.

The other operational expense charge of $3.0 million for the three months ended September 30, 2010 included a $0.8 million loss on the sale of non-dedicated tubular inventory and $2.2 million of charges related to a delay in the drilling of the second well in our Amberjack drilling program as a result of the deep water drilling moratorium. For the nine months ended September 30, 2010, other operational expenses of $5.5 million included a $2.2 million loss on the sale of non-dedicated tubular inventory and a total of $3.3 million of charges related to a delay in the drilling of the second well in our Amberjack drilling program as a result of the deep water drilling moratorium. The other operational expense charge of $2.4 million for the nine months ended September 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 three months ended September 30, 2010 totaled $59.0 million, or $3.24 per Mcfe, compared to $67.2 million, or $3.06 per Mcfe, during the comparable period of 2009. For the nine months ended September 30, 2010 and 2009, DD&A expense totaled $180.4 million and $181.9 million, respectively.

Accretion expense for the three months ended September 30, 2010 was $6.6 million compared to $8.1 million for the comparable period of 2009. For the nine months ended September 30, 2010 and 2009, accretion expense totaled $19.8 million and $24.9 million, respectively. The decrease is primarily due to a decrease in our credit adjusted risk free rate at December 31, 2009.

Salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) for the three months ended September 30, 2010 were $9.8 million compared to $9.5 million for the three months ended September 30, 2009. For the nine months ended September 30, 2010 and 2009, SG&A totaled $30.2 million and $31.1 million, respectively.

The impairment of inventory for the three months ended September 30, 2009 totaled $1.3 million and related to the write-down of our tubular inventory. For the nine months ended September 30, 2009, the impairment charge totaled $8.5 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 three months ended September 30, 2010 totaled $2.7 million, net of $8.0 million of capitalized interest, compared to interest expense of $5.2 million, net of $6.6 million of capitalized interest, during the comparable 2009 period. For the nine months ended September 30, 2010, interest expense totaled $9.3 million, net of capitalized interest of $21.6 million, compared to interest expense of $15.1 million, net of capitalized interest of $19.4 million for the comparable 2009 period. The decrease in interest cost is primarily the result of a decrease in outstanding borrowings under our bank credit facility.

Total income taxes for the third quarter of 2010 were $13.5 million of which $10.2 million was in current income taxes. The increased effective tax rate of 40% was due to an increase in the provision for state income taxes as operational activities in the Marcellus Shale increase.

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 49% of our estimated 2010 production from estimated proved reserves, 32% of our estimated 2011 production from estimated proved reserves, and 6% of our estimated 2012 production from estimated proved reserves. See Item 1. Financial Statements — Note 3 — Derivative Instruments and Hedging Activities for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 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 total debt outstanding of $525 million at September 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 8⁵/₈% Senior Notes due 2017 and $200 million of 6³/4% Senior Subordinated Notes due 2014. At September 30, 2010, the remaining $50 million of our outstanding debt bears interest at a floating rate and consists of borrowings outstanding under our bank credit facility. At September 30, 2010, the weighted average interest rate under our bank credit facility was approximately 2.5% 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 September 30, 2010. Based on this evaluation, our principal executive officer and principal financial officer believe that as of the end of the quarterly period ended September 30, 2010:

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

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Franchise Tax Action. On December 30, 2004, Stone was served with two petitions (civil action numbers 2004-6227 and 2004-6228) filed by the Louisiana Department of Revenue (“LDR”) in the 15th Judicial District Court (Parish of Lafayette, Louisiana) claiming additional franchise taxes due. In one case, the LDR is seeking additional franchise taxes from Stone in the amount of $640,000, plus accrued interest of $352,000 (calculated through December 15, 2004), for the franchise tax year 2001. In the other case, the LDR is seeking additional franchise taxes from Stone (as successor to Basin Exploration, Inc.) in the amount of $274,000, plus accrued interest of $159,000 (calculated through December 15, 2004), for the franchise tax years 1999, 2000 and 2001. On December 29, 2005, the LDR filed another petition in the 15^th Judicial District Court claiming additional franchise taxes due for the taxable years ended December 31, 2002 and 2003 in the amount of $2.6 million plus accrued interest calculated through December 15, 2005 in the amount of $1.2 million. Also, on January 2, 2008, Stone was served with a petition (civil action number 2007-6754) claiming $1.5 million of additional franchise taxes due for the 2004 franchise tax year, plus accrued interest of $800,000 calculated through November 30, 2007. Further, on January 7, 2009, Stone was served with a petition (civil action number 2008-7193) claiming additional franchise taxes due for the taxable years ended December 31, 2005 and 2006 in the amount of $4.0 million plus accrued interest calculated through October 21, 2008 in the amount of $1.7 million. In addition, we have received assessments from the LDR for additional franchise taxes in the amount of $2.9 million resulting from audits of 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.

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 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010. Except as set forth below and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, 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 drilling platform in the Gulf of Mexico and the resulting oil spill have increased certain of the regulatory and other risks that we face and could have a material adverse effect on our business.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE,” formerly the Minerals Management Service) of the U.S. Department of the Interior issued a “Notice to Lessees” (“NTL”) on May 30, 2010, and a revised notice on July 12, 2010, implementing a moratorium on deepwater drilling activities that effectively halted deepwater drilling of wells using subsea blowout preventers (“BOPs”) or surface BOPs on a floating facility. While the moratorium was in place, the BOEMRE issued a series of NTLs and adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future. The moratorium was lifted on October 12, 2010, but offshore operators must now comply with strict new safety and operating requirements. For example, before being allowed to resume drilling in deepwater, outer continental shelf operators must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing,

BOPs, safety certification, emergency response, and worker training. Operators also must demonstrate the availability of adequate spill response and blowout containment resources. Notwithstanding the lifting of the moratorium, we anticipate that there will continue to be delays in the resumption of drilling-related activities, including delays in the issuance of drilling permits, as these various regulatory initiatives are fully implemented.

In addition to the new requirements recently imposed by the BOEMRE, there have been a variety of proposals to change existing laws and regulations that could affect our operations and cause us to incur substantial costs. Implementation of any one or more of the various proposed changes could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory burdens, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico and other offshore waters more difficult, more time consuming, and more costly. For example, Congress is currently considering a variety of amendments to the Oil Pollution Act of 1990, or “OPA”, in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the outer continental shelf waters where we have substantial operations. 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 an oil spill, including, but not limited to, the costs of responding to a spill, natural resource damages and economic damages suffered by persons adversely affected by the spill. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating in offshore waters, although the Secretary of Interior may increase this amount. If OPA is amended to significantly increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located in offshore waters or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating in offshore waters will be increased.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

In addition, the BOEMRE recently issued a NTL dated to be effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” — wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease — in the Gulf of Mexico. Historically, many oil and natural gas producers in the Gulf of Mexico have delayed the plugging, abandoning or removal of such idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The determination of productive lease termination dates are generally based on management’s estimate as to when it would become likely that production, including from future development activities, would cease on the lease. The recently issued NTL, however, sets forth more stringent standards for decommissioning timing requirements — any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. Triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. In addition, the potential increase in decommissioning activity in the Gulf of Mexico over the next few years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal

costs and increases in related asset retirement obligations. For additional information about our asset retirement obligations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Asset Retirement Obligations.”

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency, or the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

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 third quarter of 2010:


						Total Number of
						Shares (or Units)		Maximum Number (or
						Purchased as Part		Approximate Dollar Value)
	Total Number of			Average Price		of Publicly		of Shares (or Units) that May
	Shares (or Units)			Paid per Share		Announced Plans or		Yet be Purchased Under the
Period	Purchased			(or Unit)		Programs		Plans or Programs
Share Repurchase Program:
July 2010		—			—		—
August 2010		—			—		—
September 2010		—			—		—

		—			—		—	$	92,928,632

Other:
July 2010		4,431	(a)	$	10.95		—
August 2010		—			—		—
September 2010		20,628	(a)		11.66		—

		25,059		$	11.53		—		N/A

Total		25,059		$	11.53		—


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

Item 6. Exhibits


3.1		Certificate of Incorporation of the Registrant, as amended (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 November 4, 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.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	STONE ENERGY CORPORATION
Date: November 4, 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)

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 November 4, 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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