Edgar Filing: STONE ENERGY CORP

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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, 2006


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

For the transition period from to

Commission file number 1-12074

STONE ENERGY CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


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

625 E. Kaliste Saloom Road 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 is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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 October 27, 2006, there were 27,797,622 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, 2006 and December 31, 2005		1

	Condensed Consolidated Statement of Income for the Three and Nine Months Ended September 30, 2006 and 2005		2

	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2006 and 2005		3

	Notes to Condensed Consolidated Financial Statements		4

	Report of Independent Registered Public Accounting Firm		12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		18

Item 4.	Controls and Procedures		19

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings		20

Item 6.	Exhibits		22

	Signature		23

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements

STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)


	September 30,			December 31,
	2006			2005
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	28,053		$	79,708
Accounts receivable		258,538			211,685
Fair value of hedging contracts		18,098			7,471
Other current assets		819			2,795

Total current assets		305,508			301,659

Oil and gas properties — full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $2,101,452 and $1,880,180 respectively		1,934,302			1,564,312
Unevaluated		247,098			246,647
Building and land, net		5,838			5,521
Fixed assets, net		8,709			9,331
Other assets, net		18,355			12,847

Total assets	$	2,519,810		$	2,140,317


Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable to vendors	$	160,716		$	160,682
Undistributed oil and gas proceeds		52,078			59,187
Asset retirement obligations		68,600			53,894
Deferred merger expense reimbursement		25,300			—
Deferred taxes		6,133			2,646
Other accrued liabilities		23,440			8,744

Total current liabilities		336,267			285,153

Long-term debt		797,000			563,000
Deferred taxes		256,311			231,961
Asset retirement obligations		114,499			113,043
Other long-term liabilities		3,886			3,037

Total liabilities		1,507,963			1,196,194


Commitments and contingencies

Common stock		275			272
Treasury stock		(1,161	)		(1,348	)
Additional paid-in capital		500,098			500,228
Unearned compensation		—			(15,068	)
Retained earnings		499,465			455,183
Accumulated other comprehensive income		13,170			4,856

Total stockholders’ equity		1,011,847			944,123

Total liabilities and stockholders’ equity	$	2,519,810		$	2,140,317

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

STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF INCOME
(In thousands of dollars, except per share amounts)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Operating revenue:
Oil production	$	98,340		$	59,872		$	247,375		$	203,979
Gas production		83,216			99,403			259,726			296,687
Derivative income		602			—			2,670			—

Total operating revenue		182,158			159,275			509,771			500,666


Operating expenses:
Lease operating expenses		52,403			30,895			119,825			88,503
Production taxes		3,413			3,273			11,515			9,698
Depreciation, depletion and amortization		83,038			57,345			224,214			191,764
Accretion expense		3,153			1,790			9,238			5,369
Salaries, general and administrative expenses		8,027			5,205			25,092			14,698
Incentive compensation expense		3,025			246			3,630			1,259
Derivative expenses		—			4,831			—			4,831

Total operating expenses		153,059			103,585			393,514			316,122


Income from operations		29,099			55,690			116,257			184,544


Other (income) expenses:
Interest		11,579			5,781			24,386			17,546
Other income, net		(2,023	)		(827	)		(4,683	)		(2,659	)
Merger expense reimbursement		—			—			(18,200	)		—
Merger expenses		490			—			46,973			—

Total other expenses		10,046			4,954			48,476			14,887


Income before taxes		19,053			50,736			67,781			169,657


Provision (benefit) for income taxes:
Current		170			—			170			—
Deferred		(2,875	)		17,758			23,297			59,285

Total income taxes (benefit)		(2,705	)		17,758			23,467			59,285


Net income	$	21,758		$	32,978		$	44,314		$	110,372


Basic earnings per share	$	0.79		$	1.22		$	1.62		$	4.11
Diluted earnings per share	$	0.79		$	1.20		$	1.62		$	4.06

Average shares outstanding		27,454			27,025			27,313			26,882
Average shares outstanding assuming dilution		27,619			27,389			27,429			27,194

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,
	2006			2005
Cash flows from operating activities:
Net income	$	44,314		$	110,372
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		224,214			191,764
Accretion expense		9,238			5,369
Provision for deferred income taxes		23,297			59,285
Non-cash merger expenses, net		25,300			—
Stock compensation expense		3,234			—
Derivative expenses (income)		(870	)		3,295
Other non-cash items		1,169			2,250
(Increase) decrease in accounts receivable		(46,853	)		7,095
(Increase) decrease in other current assets		1,939			(2,739	)
Increase in accounts payable		723			1,700
Increase in other current liabilities		7,587			24,269
Settlement of asset retirement obligations		—			(788	)
Other		(65	)		120

Net cash provided by operating activities		293,227			401,992


Cash flows from investing activities:
Investment in oil and gas properties		(582,754	)		(404,742	)
Proceeds from sale of oil and gas properties		(38	)		1,549
Investment in fixed and other assets		(2,023	)		(4,564	)

Net cash used in investing activities		(584,815	)		(407,757	)


Cash flows from financing activities:
Proceeds from bank borrowings		85,000			76,000
Repayment of bank borrowings		(76,000	)		(45,000	)
Proceeds from issuance of senior floating rate notes		225,000			—
Deferred financing costs		(3,282	)		(187	)
Proceeds from the exercise of stock options		9,215			13,100

Net cash provided by financing activities		239,933			43,913


Net increase (decrease) in cash and cash equivalents		(51,655	)		38,148

Cash and cash equivalents, beginning of period		79,708			24,257


Cash and cash equivalents, end of period	$	28,053		$	62,405

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 and subsidiary as of September 30, 2006 and for the three and nine-month periods ended September 30, 2006 and 2005 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, 2005 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 the explanatory note regarding restatement and management’s discussion and analysis of financial condition and results of operations, contained in our Annual Report on Form 10-K/A for the year ended December 31, 2005. The results of operations for the three and nine-month periods ended September 30, 2006 are not necessarily indicative of future financial results.

Note 2 — Earnings Per Share

Basic net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the period. Diluted net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the period plus the weighted-average number of dilutive stock options and restricted stock granted to outside directors and employees. There were approximately 166,000 and 364,000 dilutive shares for the three months ended September 30, 2006 and 2005, respectively, and 116,000 and 312,000 dilutive shares for the nine months ended September 30, 2006 and 2005, respectively.

Stock options that were considered antidilutive because the exercise price of the option exceeded the average price of our stock for the applicable period totaled approximately 532,000 and 369,000 shares in the three months ended September 30, 2006 and 2005, respectively, and 532,000 and 588,000 shares in the nine months ended September 30, 2006 and 2005, respectively.

During the three months ended September 30, 2006 and 2005, approximately 122,000 and 215,000 shares of common stock, respectively, were issued upon the exercise of stock options and vesting of restricted stock by employees and nonemployee directors. For the nine months ended September 30, 2006 and 2005, approximately 348,000 and 466,000 shares of common stock, respectively, were issued upon the exercise of stock options and vesting of restricted stock by employees and nonemployee directors and the awarding of employee bonus stock pursuant to the 2004 Amended and Restated Stock Incentive Plan.

Note 3 — Ceiling Test

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”. In the event net capitalized costs of proved oil and gas properties, net of related deferred taxes, exceeds the present value of estimated future net cash flows from proved reserves, a write-down is necessary. For purposes of the ceiling test computation, the present value of the estimated future net cash flows is based on period-end hedge adjusted commodity prices (or in cases where prices have increased after the period end date, then on the hedge adjusted prices at the later date) and excludes reductions of cash flows related to estimated abandonment costs on proved developed properties.

For the quarter ended September 30, 2006, our ceiling test computation indicated that no write-down was necessary. For purposes of the ceiling test computation, we used hedge adjusted market prices subsequent to the period end date. These prices were based on a Henry Hub gas price of $7.92 per MMBtu and a West Texas Intermediate oil price of $60.75 per barrel. Had we used period end prices, we would have incurred a write-down of $281.2 million after income taxes. Period end prices were based on a Henry Hub gas price of $4.175 per MMBtu and a West Texas Intermediate oil price of $62.91 per barrel. For purposes of the ceiling test computation, cash flow hedges of oil and gas production in place at September 30, 2006 increased the present value of estimated future net cash flows from proved reserves by approximately $20 million.

Note 4 — Hedging Activities

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. The primary objective of these activities is to reduce our exposure to the risk of declining oil and natural gas prices during the term of the hedge. We do not enter into hedging transactions for trading purposes. We currently utilize zero-premium collars for hedging purposes.

The following table illustrates our hedging positions as of September 30, 2006:


	Zero-Premium Collars
	Natural Gas						Oil
	Daily						Daily
	Volume		Floor		Ceiling		Volume		Floor		Ceiling
	(MMBtus/d)		Price		Price		(Bbls/d)		Price		Price
2006		10,000	$	8.00	$	14.28		3,000	$	55.00	$	76.40
2006		20,000		9.00		16.55		2,000		60.00		78.20
2006		20,000		10.00		16.40		—		—		—
2007		—		—		—		3,000		60.00		78.35
2007		—		—		—		3,000		60.00		93.05
2008		—		—		—		3,000		60.00		90.20

Under Statement of Financial Accounting Standards (“SFAS”) No. 133, 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, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production. Instruments not qualifying for hedge accounting are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings. Monthly settlements of ineffective hedges are recognized in earnings through derivative expense (income) and are not reflected as revenue from oil and natural gas production.

During the three months ended September 30, 2006, we realized a net increase in natural gas revenue related to our effective zero-premium collars of $11.5 million. We realized a net decrease of $4.7 million in natural gas revenue related to our effective swaps and a net decrease of $6.1 million in oil revenue related to our effective zero-premium collars for the three months ended September 30, 2005. During the nine months ended September 30, 2006, we realized a net increase in natural gas revenue related to our effective zero-premium collars of $25.5 million. We realized a net decrease of $11.2 million in natural gas revenue related to our effective swaps and a net decrease of $7.5 million in oil revenue related to our effective zero-premium collars for the nine months ended September 30, 2005.

During the quarter ended September 30, 2006, 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. During the quarter ended September 30, 2005, as a result of extended shut-ins of production after Hurricane Katrina and Hurricane Rita, our September, October and November 2005 crude oil production levels were below the volumes that we had hedged. Consequently, one of our crude oil hedges for the months of September, October and November 2005 was deemed to be ineffective. Derivative expense (income) for the three and nine months ended September 30, 2006 and 2005 consisted of the following:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005
	(In millions)
Cash settlement on the ineffective portion of derivatives		($0.8	)	$	1.5		($1.8	)	$	1.5
Changes in fair market value of ineffective portion of derivatives		0.2			3.3		(0.9	)		3.3

Total derivative expense (income)		($0.6	)	$	4.8		($2.7	)	$	4.8

Note 5 — Long-Term Debt

Long-term debt consisted of the following at:


	September 30,		December 31,
	2006		2005
	(In millions)
8¹/4% Senior Subordinated Notes due 2011	$	200	$	200
6³/4% Senior Subordinated Notes due 2014		200		200
Senior Floating Rate Notes due 2010		225		—
Bank debt		172		163


Total long-term debt	$	797	$	563

On June 28, 2006, we closed a private placement of $225 million aggregate principal amount of senior floating rate notes due 2010. Net proceeds from the sale of the notes were $222.2 million. The notes bear interest at a rate per annum, reset quarterly, equal to LIBOR plus the applicable margin, initially 2.75%. The applicable margin will increase by 1% on July 15, 2007. Interest will be payable on January 15th, April 15th, July 15th and October 15th of each year, commencing on October 15th, 2006. The notes have a final maturity date of July 15, 2010. The notes are unsecured senior obligations and are subordinated to all of our secured debt, including indebtedness under our credit facility, and all indebtedness and other obligations of our subsidiaries. The notes rank pari passu in right of payment to all of our existing and future senior indebtedness. The notes will be required to be redeemed, in whole, after the occurrence of any Change of Control (as defined in the Indenture governing the notes), at the principal amount of the notes plus accrued and unpaid interest to the date of redemption. The notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments.

On July 14, 2006, the borrowing base under the credit facility was increased to $325 million in connection with the preferential rights acquisition of additional working interests in Mississippi Canyon Blocks 109 and 108 (see Note 11). Borrowings outstanding at September 30, 2006 under the facility totaled $172 million, and letters of credit totaling $56.9 million had been issued under the facility. At September 30, 2006, we had $96.1 million of borrowings available under the credit facility and the weighted average interest rate was approximately 6.8% per annum. As of October 31, 2006, we had borrowings outstanding under the credit facility of $172 million and $52.8 million of letters of credit outstanding resulting in $100.2 million of available borrowings. The borrowing base under the credit facility is re-determined periodically based on the bank group’s evaluation of our proved oil and gas reserves.

Note 6 — Comprehensive Income

The following table illustrates the components of comprehensive income for the three and nine months ended September 30, 2006 and 2005:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006		2005			2006		2005
	(In millions)
Net income	$	21.8	$	33.0		$	44.3	$	110.4
Other comprehensive income (loss), net of tax effect:
Adjustment for fair value accounting of derivatives		4.2		(11.2	)		8.3		(15.0	)

Comprehensive income	$	26.0	$	21.8		$	52.6	$	95.4

Note 7 — Asset Retirement Obligations

During the third quarter of 2006 and 2005, we recognized non-cash expenses of $3.2 million and $1.8 million, respectively, related to the accretion of our asset retirement obligations. For the nine-month periods ended September 30, 2006 and 2005, we recognized accretion expense of $9.2 million and $5.4 million, respectively. During the quarter ended September 30, 2006, the asset retirement obligation was increased by $7.0 million in connection with the preferential rights acquisition of additional working interests in Mississippi Canyon Blocks 109 and 108.

Note 8 — Stock-Based Compensation

On December 16, 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB Opinion No. 25 and amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123(R) became effective for us on January 1, 2006.

We have elected to adopt the requirements of SFAS No. 123(R) using the “modified prospective” method. Under this method, compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. For the three months ended September 30, 2006, we incurred $2.3 million of stock-based compensation, of which $1.4 million related to restricted stock issuances and $0.9 million related to stock option grants and of which a total of approximately $1.0 million was capitalized into Oil and Gas Properties. For the nine months ended September 30, 2006, we incurred $7.0 million of stock-based compensation, of which $4.0 million related to restricted stock issuances, $2.8 million related to stock option grants and $0.2 million related to employee bonus stock awards and of which a total of approximately $3.2 million was capitalized into Oil and Gas Properties. The net effect of the implementation of SFAS No. 123(R) on net income for the three and nine-month periods ended September 30, 2006 was immaterial.

For the three and nine-month periods ended September 30, 2005, if stock-based compensation expense had been determined consistent with the expense recognition provisions under SFAS No. 123, our net income, basic earnings per share and diluted earnings per share would have approximated the pro forma amounts below:


	Three Months			Nine Months
	Ended			Ended
	September 30, 2005			September 30, 2005
	(In millions, except per share amounts)
Net income	$	33.0		$	110.4
Add: Stock-based compensation expense included in net income, net of tax		0.3			0.5
Less: Stock-based compensation expense using fair value method, net of tax		(0.8	)		(1.8	)

Pro forma net income	$	32.5		$	109.1


Basic earnings per share	$	1.22		$	4.11
Pro forma basic earnings per share	$	1.20		$	4.06

Diluted earnings per share	$	1.20		$	4.06
Pro forma diluted earnings per share	$	1.19		$	4.01

Under our 2004 Amended and Restated Stock Incentive Plan (the “Plan”), we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire ten years subsequent to award. In addition, the Plan provides that shares available under the Plan may be granted as restricted stock. Restricted stock typically vests over a three-year period. During the nine months ended September 30, 2006 and 2005, we granted 15,000 stock options valued at $313,500 and 85,500 stock options valued at $1,780,000, respectively. Fair value for the nine months ended September 30, 2006 and 2005 was determined using the Black-Scholes option pricing model with the following assumptions:


	2006			2005
Dividend yield		0.00	%		0.00	%
Expected volatility		36.59	%		36.47	%
Risk-free rate		4.58	%		3.84	%
Expected option life	6.0 years			6.0 years
Forfeiture rate		10.00	%		0.00	%

Expected volatility and expected option life are based on a historical average. The risk-free rate is based on quoted rates on zero-coupon Treasury Securities for terms consistent with the expected option life.

During the nine months ended September 30, 2006, we issued 52,050 shares of restricted stock valued at $2,376,000. The fair value of restricted shares is determined based on the average of the high and low prices on the issuance date and assumes a 5% forfeiture rate.

A summary of activity under the Plan during the nine months ended September 30, 2006 is as follows:


	Number						Aggregate
	of			Wgtd. Avg.		Wgtd. Avg.	Intrinsic
	Options			Exer. Price		Term	Value
Options outstanding, beginning of period		1,902,062		$	41.99
Granted		15,000			47.75
Exercised		(270,669	)		34.04
Forfeited		(60,460	)		38.31
Expired		(120,264	)		55.71

Options outstanding, end of period		1,465,669			42.54	5.4 years	$	4,284,487

Options exercisable, end of period		928,733			43.95	4.4 years		2,907,591

Options unvested, end of period		536,936			40.11	7.1 years		1,376,896


	Number of			Wgtd. Avg.
	Restricted			Fair Value
	Shares			Per Share
Restricted stock outstanding, beginning of period		344,038		$	51.52
Issuances		52,050			45.65
Lapse of restrictions		(100,596	)		51.34
Forfeitures		(26,107	)		52.58

Restricted stock outstanding, end of period		269,385			50.35

The weighted average grant-date fair value of options granted during the nine months ended September 30, 2006 was $20.90. The total intrinsic value of options exercised during the nine months ended September 30, 2006 was $3.4 million. The weighted average issuance date fair value of restricted shares issued during the nine months ended September 30, 2006 was $45.65.

As of September 30, 2006, there was $17.8 million of unrecognized compensation cost related to non-vested share-based compensation arrangements under the Plan. That cost is being amortized on a straight-line basis over the vesting period and is expected to be recognized over a weighted-average period of 2.0 years.

Note 9 — Merger

On June 22, 2006, we entered into an Agreement and Plan of Merger (“EPL Merger Agreement”) with Energy Partners, Ltd. (“EPL”) and EPL Acquisition Corp. LLC (“EPL Acquisition”), a wholly-owned subsidiary of EPL. On October 11, 2006, we entered into an agreement with EPL and EPL Acquisition pursuant to which the EPL Merger Agreement was terminated (“EPL Termination Agreement”). Under the terms of the EPL Termination Agreement, EPL paid $8.0 million to us, which will be recognized in earnings in our fourth quarter 2006 financial statements.

Prior to entering into the EPL Merger Agreement, we terminated our merger agreement with Plains Exploration and Production Company (“Plains”) and Plains Acquisition Corp. (“Plains Acquisition”) on June 22, 2006. As required under the terms of the terminated merger agreement among Stone, Plains and Plains Acquisition, Plains was entitled to a termination fee of $43.5 million (“Plains Termination Fee”), which was advanced by EPL to Plains on June 22, 2006. Pursuant to the EPL Merger Agreement, we were obligated to repay all or a portion of this termination fee under certain circumstances if the EPL merger was not consummated. The $43.5 million termination fee was recorded as merger expenses in the income statement in the second quarter of 2006. Of this amount, $25.3 million was potentially reimbursable to EPL under certain circumstances described in the EPL Merger Agreement and therefore was recorded as deferred revenue on the balance sheet as of June 30, 2006 and September 30, 2006. The EPL Termination Agreement provided for a waiver of the reimbursement of the Plains Termination Fee and, consequently, the $25.3 million of deferred revenue will be recognized in earnings as merger expense reimbursement in our fourth quarter 2006 financial statements. The remaining $18.2 million of the termination fee was recorded as merger expense reimbursement in the income statement for the three months ended June 30, 2006.

Merger expenses are now expected to be deductible for income tax purposes and merger expense reimbursements are now expected to be taxable for income tax purposes. Through the second quarter of 2006 merger expenses were anticipated to be non-deductible and merger expense reimbursements were expected to be non-taxable in anticipation of a successful closing under the EPL Merger Agreement. A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:


	Three Months			Nine Months
	Ended			Ended
	September 30, 2006			September 30, 2006
Income tax expense computed at the statutory federal income tax rate		35.0	%		35.0	%
State taxes		0.2			0.2
Effect of second quarter expected nondeductible merger expenses and nontaxable reimbursement deemed to be deductible and taxable in third quarter of 2006		(47.4	)		—
Other — reversal of valuation allowance		(2.0	)		(0.6	)

Effective income tax rate		(14.2	%)		34.6	%

Note 10 — International Operations

In the first quarter of 2006, we entered into an agreement to participate in the drilling of two exploratory wells on two offshore concessions in Bohai Bay, China. After drilling these two wells, we will have the option to earn interests in the two concessions, which collectively cover approximately 749,000 acres. The first well encountered potential oil pay in two separate intervals. The possible discovery is awaiting appraisal to determine if it is commercial. The second exploratory well spudded late in the third quarter of 2006. Included in unevaluated oil and gas property costs at September 30, 2006 are $18.8 million of capital expenditures related to our properties in Bohai Bay, China.

Note 11 — Property Acquisition

On July 14, 2006, we completed a $192.0 million acquisition of additional working interests in Mississippi Canyon Blocks 109 and 108. The acquisition was financed with a portion of the proceeds from the private placement of $225 million aggregate principal amount of senior floating rate notes due 2010 (see Note 5). With the acquisition, we increased our working interest in Mississippi Canyon Block 109 from 33% to 100% and in Mississippi Canyon Block 108 from 16.5% to 24.8%.

Note 12 — Commitments and Contingencies

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 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 years 1999, 2000 and 2001. Further, 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. 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. Stone has not yet been given any indication that the LDR plans to review franchise taxes for the franchise tax years 2004 and 2005.

Stone has received notice that the staff of the SEC (the “Staff”) is conducting an informal inquiry into the revision of Stone’s proved reserves and the financial statement restatement. The Staff has also informed Stone that it is likely to obtain a formal order of investigation with its inquiry. In addition, Stone has received an inquiry from the Philadelphia Stock Exchange investigating matters including trading prior to Stone’s October 6, 2005 announcement. Stone intends to cooperate fully with both inquiries.

On or around November 30, 2005, George Porch filed a putative class action in the United States District Court for the Western District of Louisiana against Stone, David Welch, Kenneth Beer, D. Peter Canty and James Prince purporting to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. Three similar complaints were filed soon thereafter. All complaints had asserted a putative class period commencing on June 17, 2005 and ending on October 6, 2005. All complaints contended that, during the putative class period, defendants, among other things, misstated or failed to disclose (i) that Stone had materially overstated Stone’s financial results by overvaluing its oil reserves through improper and aggressive reserve methodologies; (ii) that the Company lacked adequate internal controls and was therefore unable to ascertain its true financial condition; and (iii) that as a result of the foregoing, the values of the Company’s proved reserves, assets and future net cash flows were materially overstated at all relevant times. On March 17, 2006, these purported class actions were consolidated, with El Paso Fireman & Policeman’s Pension Fund designated as Lead Plaintiff. Lead plaintiff filed a consolidated class action complaint on or about June 14, 2006. The consolidated complaint alleges claims similar to those described above and expands the putative class period to commence on May 2, 2001 and to end on March 10, 2006. On September 13, 2006, Stone and the individual defendants filed motions seeking dismissal of that action.

were filed thereafter in the Federal Court by Joint Pension Fund, Local No. 164, I.B.E.W., and in the 15^th Judicial District Court, Parish of Lafayette, Louisiana (the “State Court”) by Gregory Sakhno. Stone was named as a nominal defendant and David Welch, Kenneth Beer, D. Peter Canty, James Prince, James Stone, John Laborde, Peter Barker, George Christmas, Richard Pattarozzi, David Voelker, Raymond Gary, B.J. Duplantis and Robert Bernhard were named as defendants in these actions. The State Court action purportedly alleges breach of the fiduciary duty, abuse of control, gross mismanagement, and waste of corporate assets against all defendants, and claims of unjust enrichment and insider selling against certain individual defendants. The Federal Court actions assert purported claims against all defendants for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets and unjust enrichment and claims against certain individual defendants for breach of fiduciary duty and violations of the Sarbanes-Oxley Act of 2002.

On March 30, 2006, the Federal Court entered an order naming Robert Farer, Priscilla Fisk and Joint Pension Fund, Local No. 164, I.B.E.W. as co-lead plaintiffs in the Federal Court derivative action and directed the lead plaintiffs to file a consolidated amended complaint within forty-five days. On April 22, 2006, the complaint in the State Court derivative action was amended to also assert claims on behalf of a purported class of shareholders of Stone. In addition to the above mentioned claims, the amended State Court derivative action complaint purports to allege breaches of fiduciary duty by the director defendants in connection with the then proposed merger transaction with Plains and seeks an order enjoining the director defendants from entering into the then proposed transaction with Plains. On May 15, 2006, the complaint in the Federal Court action was similarly amended. On September 15, 2006, co-lead plaintiffs’ in the Federal Court derivative action amended their complaint to seek an order enjoining Stone’s proposed merger with EPL based on substantially the same grounds previously asserted regarding the prior proposed transaction with Plains. On October 2, 2006, each of the defendants in the Federal Court derivative action filed or joined in motions seeking dismissal of all or part of that action.

On or around August 28, 2006, ATS instituted an action (the “ATS Litigation”) in the Delaware Court of Chancery for New Castle County (the “Delaware Court”). The initial complaint in the ATS Litigation, among other things, challenged certain provisions of the EPL Merger Agreement pursuant to which EPL (i) paid the $43.5 million Plains Termination Fee; and (ii) agreed, under certain contractually specified conditions, to pay Stone $25.6 million in the event of a future termination of the Merger Agreement (the “EPL Termination Fee”). On or around September 12, 2006, a purported shareholder of EPL filed a purported class action in the Delaware Court (the “Farrington Action”). The initial Farrington Action complaint asserted claims similar to those in the ATS Litigation and sought, among other things, a damages recovery in the amount of the Plains Termination Fee.

On or around September 7, 2006, EPL commenced an action against Stone in the Delaware Court (the “Declaratory Action”), in which EPL sought a declaratory judgment with respect to EPL’s rights and obligations under Section 6.2(e) of the Merger Agreement. On September 11, 2006, the Delaware Court expedited the Declaratory Action and consolidated with the Declaratory Action a portion of the ATS Litigation in which ATS likewise asserted claims respecting Section 6.2(e) of the Merger Agreement. By oral ruling on September 27, 2006, and subsequent written opinion dated October 11, 2006, the Delaware Court ruled, among other things, that Section 6.2(e) of the Merger Agreement did not limit the ability of EPL to explore and negotiate, in good faith, with respect to any Third Party Acquisition Proposals (as defined in the Merger Agreement), including the tender offer by ATS, Inc. for all of the outstanding shares of EPL stock at $23.00 per share (“ATS Offer”). The Delaware Court dismissed without prejudice the remainder of the claims raised by EPL in the Declaratory Action as not ripe for a judicial determination.

On October 11, 2006, EPL and Stone entered into an agreement (the “Termination and Release Agreement”) pursuant to which they agreed, among other things, (i) to enter into a mutual termination of the Merger Agreement, (ii) to mutually release certain actual or potential claims or rights of action, (iii) to mutually seek a dismissal of the Declaratory Action, and (iv) that EPL would make a payment of $8 million to Stone (the “$8 Million Payment”). EPL made the $8 Million Payment to Stone. On October 13, 2006, the Declaratory Action was dismissed by stipulation of the parties and order of the Delaware Court.

On or around October 16, 2006, following the execution of the Termination and Release Agreement, plaintiffs in both the ATS Litigation and the Farrington Litigation sought (and were later granted leave by the Court) to file Second Amended Complaints that, among other things, added claims seeking a recovery in the amount of the $8 Million Payment. On October 26, 2006, ATS voluntarily dismissed the ATS Litigation without prejudice, while — as of this date — the Farrington Action remains pending. The Delaware Court has yet to reach a determination as to the merits of the claims asserted in the Farrington Action with respect to the Plains Termination Fee or the $8 Million Payment.

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

a range of possible losses or any minimum loss from such matters. Furthermore, to the extent that our insurance policies are ultimately available to cover any costs and/or liabilities resulting from these actions, they may not be sufficient to cover all costs and liabilities incurred by us and our current and former officers and directors in these regulatory and civil proceedings.

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, 2006, and the related condensed consolidated statement of income for the three and nine-month periods ended September 30, 2006 and 2005, and the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2006 and 2005. 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 the Public Company Accounting Oversight Board (United States), 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, 2005, and the related consolidated statements of income, cash flows, changes in stockholders’ equity and comprehensive income for the year then ended (not presented herein) and in our report dated March 7, 2006, 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, 2005, 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
October 30, 2006

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

This Form 10-Q and the information referenced herein contain statements that constitute “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. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. We use the terms “Stone,” “Stone Energy,” “Company,” “we,” “us” and “our” to refer to Stone Energy Corporation.

When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in our Annual Report on Form 10-K. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. 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 Stone Energy Corporation 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/A for the year ended December 31, 2005.

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 in the conventional shelf of the Gulf of Mexico (the “GOM”), the deep shelf of the GOM, deep water of the GOM and several basins in the Rocky Mountain Region. Our business strategy is to increase reserves, production and cash flow through the acquisition, exploitation and development of mature properties in the Gulf Coast Basin and exploring opportunities in the deep water environment of the Gulf of Mexico, Rocky Mountain Region and other potential areas. Throughout this document, reference to our “Gulf Coast Basin” properties includes our onshore, shelf and deep shelf properties. Reference to our “Rocky Mountain Region” includes our properties in several Rocky Mountain Basins and the Williston Basin. All period to period comparisons are based on restated amounts (see Explanatory Notes and Note 1 — Restatement of Historical Financial Statements contained in our Annual Report on Form 10-K/A for the year ended December 31, 2005).

On June 22, 2006, we entered into an Agreement and Plan of Merger (“EPL Merger Agreement”) with Energy Partners, Ltd. (“EPL”) and EPL Acquisition Corp. LLC, a wholly-owned subsidiary of EPL. On October 11, 2006, we entered into an agreement with EPL and EPL Acquisition pursuant to which the EPL Merger Agreement was terminated and EPL paid Stone $8.0 million and released all claims to the Plains $43.5 million termination fee.

Critical Accounting Policies

Our Annual Report on Form 10-K/A 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; 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/A 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 our Annual Report on Form 10-K/A regarding these other risk factors.

Liquidity and Capital Resources

Cash Flow. Net cash flow provided by operating activities for the nine months ended September 30, 2006 was $293.2 million compared to $402.0 million reported in the comparable period in 2005.

Net cash flow used in investing activities totaled $584.8 million and $407.8 million during the first nine months of 2006 and 2005, respectively, which primarily represents our investment in oil and gas properties. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2006 capital expenditures (excluding acquisitions) with cash flow provided by operating activities.

Net cash flow provided by financing activities totaled $239.9 million for the nine months ended September 30, 2006, which primarily represents proceeds from the issuance of our senior floating rate notes due 2010, borrowings net of repayments under our bank credit facility and proceeds from the exercise of stock options. For the nine months ended September 30, 2005, net cash flow provided by financing activities totaled $43.9 million, which primarily represents borrowings net of repayments under our bank credit facility and proceeds from the exercise of stock options. In total, cash and cash equivalents decreased from $79.7 million as of December 31, 2005 to $28.1 million as of September 30, 2006.

We had a working capital deficit at September 30, 2006 in the amount of $30.8 million. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity. “Liquidity” is defined as the ability to obtain cash quickly either through the conversion or assets or incurrence of liabilities. See “Bank Credit Facility”.

Capital Expenditures. Third quarter 2006 additions to oil and natural gas property costs of $299.4 million included $196.9 million of acquisition costs, $7.3 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $4.9 million of capitalized interest. Year-to-date 2006 additions to oil and natural gas property costs of $591.7 million included $219.9 million of acquisition costs, $18.1 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $13.4 million of capitalized interest. These investments were financed by cash flow from operating activities, borrowings under our credit facility, proceeds from the issuance of our senior floating rate notes and working capital.

Our 2006 capital expenditures budget, excluding property acquisitions, lease acquisitions, asset retirement costs and capitalized interest and general and administrative expenses, is approximately $385 million. Based upon our outlook of commodity prices and our estimated production, we expect to fund our 2006 capital program with cash flow provided by operating activities. To the extent that 2006 cash flow from operating activities exceeds our estimated 2006 capital expenditures, we may pay down a portion of our existing debt. If cash flow from operating activities during 2006 is not sufficient to fund estimated 2006 capital expenditures, we believe that our bank credit facility will provide us with adequate liquidity. See “Bank Credit Facility”.

Bank Credit Facility. In July 2006, the borrowing base under our credit facility was increased to $325 million in connection with the preferential rights acquisition of additional working interests in Mississippi Canyon Blocks 109 and 108. Borrowings outstanding at September 30, 2006 under the facility totaled $172 million, and letters of credit totaling $56.9 million had been issued under the facility. At September 30, 2006, we had $96.1 million of borrowings available under the credit facility and the weighted average interest rate was approximately 6.8% per annum. As of October 31, 2006, we had borrowings outstanding under the credit facility of $172 million and $52.8 million of letters of credit outstanding resulting in $100.2 million of available borrowings. The borrowing base under the credit facility is re-determined periodically based on the bank group’s evaluation of our proved oil and natural gas reserves.

Known Trends and Uncertainties

International Operations. Included in unevaluated oil and gas property costs at September 30, 2006 are $18.8 million of capital expenditures related to our properties in Bohai Bay, China. Under full cost accounting, investments in individual countries represent separate cost centers for computation of depreciation, depletion and amortization as well as for full cost ceiling test evaluations. Given that this is our sole investment to date in the Peoples Republic of China, it is possible that upon a more complete evaluation of this project that some or all of this investment would be reclassed as a charge to expense on our income statement.

Results of Operations

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


	Three Months Ended
	September 30,
	2006		2005		Variance			% Change
Production:
Oil (MBbls)		1,465		1,111		354			32	%
Natural gas (MMcf)		10,971		12,728		(1,757	)		(14	%)
Oil and natural gas (MMcfe)		19,761		19,394		367			2	%
Revenue data (in thousands) (a):
Oil revenue	$	98,340	$	59,872	$	38,468			64	%
Natural gas revenue		83,216		99,403		(16,187	)		(16	%)

Total oil and natural gas revenue	$	181,556	$	159,275	$	22,281			14	%
Average prices (a):
Oil (per Bbl)	$	67.13	$	53.89	$	13.24			25	%
Natural gas (per Mcf)		7.59		7.81		(0.22	)		(3	%)
Oil and natural gas (per Mcfe)		9.19		8.21		0.98			12	%
Expenses (per Mcfe):
Lease operating expenses	$	2.65	$	1.59	$	1.06			67	%
Salaries, general and administrative expenses (b)		0.41		0.27		0.14			52	%
DD&A expense on oil and gas properties		4.15		2.92		1.23			42	%


	Nine Months Ended
	September 30,
	2006		2005		Variance			% Change
Production:
Oil (MBbls)		3,803		4,080		(277	)		(7	%)
Natural gas (MMcf)		33,139		44,260		(11,121	)		(25	%)
Oil and natural gas (MMcfe)		55,957		68,740		(12,783	)		(19	%)
Revenue data (in thousands) (a):
Oil revenue	$	247,375	$	203,979	$	43,396			21	%
Natural gas revenue		259,726		296,687		(36,961	)		(12	%)

Total oil and natural gas revenue	$	507,101	$	500,666	$	6,435			1	%
Average prices (a):
Oil (per Bbl)	$	65.05	$	49.99	$	15.06			30	%
Natural gas (per Mcf)		7.84		6.70		1.14			17	%
Oil and natural gas (per Mcfe)		9.06		7.28		1.78			24	%
Expenses (per Mcfe):
Lease operating expenses	$	2.14	$	1.29	$	0.85			66	%
Salaries, general and administrative expenses (b)		0.45		0.21		0.24			114	%
DD&A expense on oil and gas properties		3.96		2.76		1.20			43	%


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

(b)		Exclusive of incentive compensation expense.

During the third quarter of 2006, net income totaled $21.8 million, or $0.79 per share, compared to $33.0 million, or $1.20 per share for the third quarter of 2005. For the nine months ended September 30, 2006, net income totaled $44.3 million, or $1.62 per share, compared to $110.4 million, or $4.06 per share, during the comparable 2005 period. All per share amounts are on a diluted basis.

Included in year-to-date 2006 net income is a $43.5 million termination fee incurred in connection with the proposed merger with EPL. Prior to entering into the EPL Merger Agreement, we terminated our merger agreement with Plains Exploration and Production Company (“Plains”) and Plains Acquisition Corp. (“Plains Acquisition”) on June 22, 2006. As required under the terms of the terminated merger agreement among Stone, Plains and Plains Acquisition, Plains was entitled to a termination fee of $43.5 million (“Plains termination Fee”), which was advanced by EPL to Plains on June 22, 2006. Pursuant to the EPL Merger Agreement, we were obligated to repay all or a portion of this termination fee under certain circumstances if the EPL merger was not consummated. The

$43.5 million termination fee was recorded as merger expenses in the income statement during the second quarter of 2006. Of this amount, $25.3 million was potentially reimbursable to EPL under certain circumstances described in the EPL Merger Agreement and therefore was recorded as deferred revenue on the balance sheet as of June 30, 2006 and September 30, 2006. The remaining $18.2 million of the termination fee was recorded as merger expense reimbursement in the income statement during the three months ended June 30, 2006.

On October 11, 2006, we entered into an agreement with EPL and EPL Acquisition pursuant to which the EPL Merger Agreement was terminated. Pursuant to the termination of the EPL Merger Agreement, EPL paid us $8 million and released all claims to the $43.5 million Plains Termination Fee. The $8.0 million fee paid to us by EPL in conjunction with the termination of the EPL Merger Agreement will be recognized in earnings in the fourth quarter of 2006. Additionally, the remaining $25.3 million of the Plains termination fee will be recognized in earnings in the fourth quarter of 2006.

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

Prices. Prices realized during the third quarter of 2006 averaged $67.13 per Bbl of oil and $7.59 per Mcf of natural gas, or 12% higher, on an Mcfe basis, than third quarter 2005 average realized prices of $53.89 per Bbl of oil and $7.81 per Mcf of natural gas. Average realized prices during the first nine months of 2006 were $65.05 per Bbl of oil and $7.84 per Mcf of natural gas compared to $49.99 per Bbl of oil and $6.70 per Mcf of natural gas realized during the first nine months of 2005. All unit pricing amounts include the cash settlement of effective hedging contracts.

During the third quarter of 2006, we realized a net increase in natural gas revenue related to our effective zero-premium collars of $11.5 million. We realized a net decrease of $4.7 million in natural gas revenue related to our effective swaps and a net decrease of $6.1 million in oil revenue related to our effective zero-premium collars for the three months ended September 30, 2005. During the nine months ended September 30, 2006, we realized a net increase in natural gas revenue related to our effective zero-premium collars of $25.5 million. We realized a net decrease of $11.2 million in natural gas revenue related to our effective swaps and a net decrease of $7.5 million in oil revenue related to our effective zero-premium collars for the nine months ended September 30, 2005.

Production. During the third quarter of 2006, total production volumes increased slightly to 19.8 Bcfe compared to 19.4 Bcfe produced during the third quarter of 2005. Oil production during the third quarter of 2006 totaled approximately 1,465,000 barrels compared to 1,111,000 barrels produced during the third quarter of 2005, while natural gas production totaled 11.0 Bcf during the third quarter of 2006 compared to12.7 Bcf produced during the third quarter of 2005. Stone’s third quarter 2006 total production rates were negatively impacted by extended Gulf Coast shut-ins due to Hurricanes Katrina and Rita, amounting to volumes of approximately 3.4 Bcfe, or 37 MMcfe per day, while the third quarter 2005 production rates reflected shut-ins due to Hurricanes Katrina and Rita, amounting to volumes of approximately 6.4 Bcfe, or 70 MMcfe per day. Without the effects of the hurricane production deferrals, quarter to quarter total production volumes decreased approximately 2.6 Bcfe, a result of natural production declines.

Year-to-date 2006 production totaled 3,803,000 barrels of oil and 33.1 Bcf of natural gas compared to 4,080,000 barrels of oil and 44.3 Bcf of natural gas produced during the comparable 2005 period, a decrease on a gas equivalent basis of 12.8 Bcfe. Year-to-date 2006 total production rates were negatively impacted by extended Gulf Coast shut-ins due to Hurricanes Katrina and Rita, amounting to volumes of approximately 14.2 Bcfe, or 52 MMcfe per day, while the third quarter 2005 production rates reflected shut-ins due do Hurricanes Katrina and Rita, amounting to volumes of approximately 6.4 Bcfe, or 23 MMcfe per day. Without the effects of the hurricane production deferrals, year to year total production volumes decreased approximately 5.0 Bcfe, a result of natural production declines.

Approximately 84% of our year-to-date 2006 production volumes were generated from our Gulf Coast Basin properties while the remaining 16% came from our Rocky Mountain Region properties.

Oil and Natural Gas Revenue. Third quarter 2006 oil and natural gas revenue totaled $181.6 million, compared to third quarter 2005 oil and natural gas revenue of $159.3 million. The increase in oil and gas revenue is primarily attributable to a 12% increase in realized oil and natural gas prices in the third quarter of 2006 over the comparable period in 2005. Year-to-date 2006 oil and natural gas revenue totaled $507.1 million compared to $500.7 million during the comparable 2005 period, representing a 1% increase.

Derivative Income/Expense. During the quarter ended September 30, 2006, 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. Derivative income for the three months ended September 30, 2006 totaled $0.6 million, consisting of $0.8 million of cash settlements on the ineffective portion of derivatives and ($0.2) million of changes in the fair market value of the ineffective portion of derivatives. Derivative income for the nine months ended September 30, 2006 totaled $2.7 million, consisting of $1.8 million of cash settlements on the ineffective portion of derivatives and $0.9 million of changes in the fair market value of the ineffective portion of derivatives.

As a result of extended shut-ins of production after Hurricane Katrina and Hurricane Rita, our September, October and November 2005 crude oil production levels were below the volumes that we had hedged. Consequently, one of our crude oil hedges for the months of September, October and November 2005 was deemed to be ineffective. During the third quarter of 2005, we recognized $4.8 million of derivative expenses, $1.5 million of which represented a charge related to the cash settlement of the ineffective September crude oil collar and $3.3 million of which represented a non-cash charge related to the mark-to-market fair value change in the ineffective October and November crude oil collars.

Expenses. Lease operating expenses during the third quarter of 2006 totaled $52.4 million compared to $30.9 million for the third quarter of 2005. Third quarter 2006 lease operating expenses included an approximate $8 million increase in property and control-of-well insurance premiums, $9.7 million of repairs in excess of estimated insurance recoveries related to damage from Hurricanes Katrina, Rita and Ivan and increased major maintenance repair activity. For the first nine months of 2006, lease operating expenses were $119.8 million, a 35% increase over the $88.5 million of lease operating expenses for the comparable period of 2005. On a unit of production basis, year-to-date 2006 lease operating expenses were $2.14 per Mcfe as compared to $1.29 per Mcfe for the comparable period in 2005. Year-to-date 2006 lease operating costs included an approximate $13 million increase in property and control-of-well insurance premiums and $20 million of repairs in excess of estimated insurance recoveries related to damage from Hurricanes Katrina, Rita and Ivan.

Depreciation, depletion and amortization (“DD&A”) on oil and gas properties for the third quarter of 2006 totaled $82.0 million, or $4.15 per Mcfe compared to $56.6 million, or $2.92 per Mcfe for the third quarter of 2005. For the nine months ended September 30, 2006 and 2005, DD&A expense totaled $221.3 million and $189.5 million, respectively. The increase in 2006 DD&A per Mcfe reflects our continued challenges in replacing production in the Gulf Coast Basin at a reasonable unit cost.

Salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) for the third quarter of 2006 were $8.0 million compared to $5.2 million in the third quarter of 2005. The third quarter 2006 increase in SG&A is primarily due to approximately $0.8 million of additional compensation expense associated with restricted stock issuances and stock option expensing and an approximate $1.3 million increase in legal and consulting fees. For the nine months ended September 30, 2006 and 2005, SG&A totaled $25.1 million and $14.7 million, respectively. The year-to-date increase in SG&A is primarily due to approximately $3.1 million of additional compensation expense associated with restricted stock issuances and stock option expensing and an approximate $4.5 million increase in legal and consulting fees.

Incentive compensation expense for the third quarter of 2006 totaled $3.0 million compared to $0.2 million for the comparable period in 2005. Year-to-date 2006 and 2005 incentive compensation expense totaled $3.6 million and $1.3 million, respectively. The increase in incentive compensation expense is due to an employee retention program put in place by the board of directors in the third quarter of 2006.

During the three months ended September 30, 2006 and 2005, we incurred $3.2 and $1.8 million, respectively, of accretion expense related to asset retirement obligations. Year-to-date 2006 and 2005 accretion expense totaled $9.2 million and $5.4 million, respectively. The increase in 2006 accretion expense is due to higher estimated asset retirement costs combined with a shortened time frame to plug and abandon our facilities.

Production taxes during the third quarter of 2006 totaled $3.4 million compared to $3.3 million in the third quarter of 2005. For the nine months ended September 30, 2006 and 2005, production taxes totaled $11.5 million and $9.7 million, respectively. The increase in year-to-date 2006 production taxes is due to a prior year ad valorem tax adjustment on certain of our Rocky Mountain properties expensed in the first quarter of 2006.

As a result of increased interest rates and the issuance of our senior floating rate notes, interest expense increased 50% to $11.6 million in the third quarter of 2006 compared to $5.8 million, in the third quarter of 2005. Interest expense totaled $24.4 million and $17.5 million during the nine months ended September 30, 2006 and 2005, respectively.

Through the second quarter of 2006, merger expenses were expected to be non-deductible and merger expense reimbursements were expected to be non-taxable in anticipation of a successful closing under the EPL Merger Agreement. As a result of the termination of the EPL Merger Agreement, merger expenses are now expected to be deductible for income tax purposes and merger expense reimbursements are now expected to be taxable for income tax purposes. This has resulted in an effective tax rate for the three and nine months ended September 30, 2006 of (14.2%) and 34.6%, respectively.

Recent Accounting Developments

Accounting for Income Taxes. On July 13, 2006, the FASB issued its Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 will be effective for fiscal years beginning after December 15, 2006.

Fair Value Accounting. On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No.157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure about fair value measurements. SFAS No.157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007.

Pension Accounting. On September 29, 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. SFAS No. 158 requires an employer to recognize the over-funded or under-funded status of a defined benefit post-retirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of the entity. SFAS No. 158 is effective for us as of the end of the fiscal year ending after December 31, 2006.

Financial Statement Misstatements. The SEC issued SAB No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements, on September 13, 2006. SAB No. 108 expresses the staff’s views regarding the process of quantifying financial statement misstatements in determining materiality. The guidance in this SAB is effective for fiscal years ending after November 15, 2006.

We have not yet determined the impact, if any, that these recent accounting developments will have on future financial reporting.

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. We do not enter into hedging transactions for trading purposes.

Our hedging policy provides that not more than one-half 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 35% — 45% of our estimated 2006 production, 15% — 20% of our estimated 2007 production and 5% — 10% of our estimated 2008 production. See Item 1. Financial Statements — Note 4 — 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 2005 Annual Report on Form 10-K/A, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

We had long-term debt outstanding of $797 million at September 30, 2006, of which $400 million, or approximately 50%, bears interest at fixed rates. The fixed rate debt as of September 30, 2006 consists of $200 million of 8¹/4% senior subordinated notes due 2011 and $200 million of 6³/4% senior subordinated notes due 2014. At September 30, 2006, the remaining $397 million of our outstanding long-term debt bears interest at a floating rate and consists of $172 million outstanding under our bank credit facility and $225 million aggregate principal amount of senior floating rate notes. At September 30, 2006, the weighted average interest rate under our bank credit facility was approximately 6.8% per annum. At September 30, 2006, the interest rate under our senior floating rate notes was equal to three-month LIBOR (as defined in the indenture governing the notes) plus an applicable margin of 2.75%. The applicable margin will increase by 1% on July 15, 2007. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates.

Item 4. Controls and Procedures

Deficiencies Relating to Reserve Reporting

In October 2005 we completed an internal review of our estimates of proved oil and natural gas reserves. As a result of this review and subsequent reviews, we reduced our estimate of total proved oil and natural gas reserves at December 31, 2004 by approximately 237 Bcfe. Management concluded that the impact of the reserve adjustment on previously issued financial statements was material and required a restatement. The audit committee of our board of directors engaged the law firm of Davis Polk & Wardwell (“Davis Polk”) to assist in its investigation of reserve revisions. Davis Polk presented its final report to the audit committee and board of directors on November 28, 2005. The final report found that a number of factors at Stone contributed to the write-down of reserves, including the following:

	•		Stone lacked adequate internal guidance or training on the SEC definition of proved reserves;

	•		There is evidence that some members of Stone management failed to fully grasp the conservatism of the SEC’s “reasonable certainty” standard of booking reserves; and

	•		There is also evidence that there was an optimistic and aggressive “tone from the top” with respect to estimating proved reserves.

As part of its final report, Davis Polk proposed a number of recommendations, including the following:

	•		adopt and distribute written guidelines to its staff on the SEC reserve reporting requirements;

	•		provide annual training for employees on the SEC requirements;

	•		continue to emphasize the difference between SEC’s standard of measuring proved reserves and the criteria that Stone might use in making business decisions; and

	•		institute and cultivate a culture of compliance to ensure that the foregoing contributing factors do not recur.

The audit committee and board of directors have accepted the Davis Polk final report, and the board of directors implemented and resolved to continue to implement all of the recommendations.

Consequently, we revised our historical proved reserves for the period from December 31, 2001 to June 30, 2005. This revision of reserves also resulted in a restatement of financial information for the years 2001 through 2004 and for the first six months of 2005. This restatement, as well as specific information regarding its impact, is discussed in Note 1 to the consolidated financial statements included in our annual report on Form 10-K/A. Restatement of previously issued financial statements to reflect the correction of a misstatement is an indicator of the existence of a material weakness in internal control over financial reporting as defined in the Public Company Accounting Oversight Board’s Auditing Standard No. 2, “An Audit of Internal Control Over Financial Reporting Performed in Conjunction with an Audit of Financial Statements.” We have identified deficiencies in our internal controls that did not prevent the overstatement of our proved oil and natural gas reserves. These deficiencies, which we believe constituted a material weakness in our internal control over financial reporting, included an overly aggressive and optimistic tone by some members of management which created a weak control environment surrounding the booking of proved oil and natural gas reserves, and inadequate training and understanding of the SEC rules for booking oil and natural gas reserves. In light of the determination that previously issued financial statements should be restated, our management concluded that a material weakness in internal control over financial reporting existed as of December 31, 2005 and disclosed this matter to the Audit Committee and our independent registered public accounting firm.

Remedial Actions

Our management, at the direction of our board of directors, is actively working to improve the control environment and to implement controls and procedures that will ensure the integrity of our proved reserve booking process.

We have implemented the following actions to mitigate weaknesses identified:

•		Those members of management that the Davis Polk report specifically suggested contributed to the aggressive and optimistic tone of management in booking estimated proved reserves are no longer employed by or affiliated with Stone as employees, officers or directors.

•		A new Vice President, Reserves, has been appointed to oversee the booking of estimated proved reserves and the training of all personnel involved in the reserve estimation process.

•		Formal training programs have been implemented and all personnel involved in the reserve estimation process have, since the announcement of the reserve revision, received formal training in SEC requirements for reporting estimated proved reserves.

•		A nationally recognized engineering firm with greater capabilities for geological reviews was contracted to audit our

		Gulf Coast Basin reserves. The Gulf Coast Basin is the area where the downward revisions occurred. Such audit was conducted as of December 31, 2005 and was completed early in 2006.

•		We have adopted and distributed a written policy and guidelines for booking estimated proved reserves to all personnel involved in the reserve estimation process.

•		We have had 100% of our proved reserves fully engineered by outside engineering firms.

We intend to continue to move forward with the following remedial actions in 2006:

•		continue our formal training programs; and

•		during 2006 and thereafter, consult with our outside engineering firms on an interim basis on the original booking of significant acquisitions, extensions, discoveries and other additions.

Evaluation of Disclosure Control and Procedures

Our Chief Executive Officer and our Chief Financial Officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. In making this evaluation, the Chief Executive Officer and the Chief Financial Officer considered the issues discussed above, together with the remedial steps we have taken. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, because of the material weakness discussed above, as of September 30, 2006, our disclosure controls and procedures were not effective in recording, processing, summarizing and reporting information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934.

Changes in Internal Control Over Financial Reporting

During 2005, we implemented the following actions to improve our control environment and to implement controls and procedures that will ensure the integrity of our reserve booking process:

•		Those members of management that the Davis Polk report specifically suggested contributed to the aggressive and optimistic tone of management in booking estimated proved reserves are no longer employed by or affiliated with Stone as employees, officers or directors.

•		A new Vice President, Reserves, has been appointed to oversee the booking of estimated proved reserves and the training of all personnel involved in the reserve estimation process.

•		Formal training programs have been implemented and all personnel involved in the reserve estimation process have, since the announcement of the reserve revision, received formal training in SEC requirements for reporting estimated proved reserves.

•		A nationally recognized engineering firm with greater capabilities for geological reviews was contracted to audit our Gulf Coast Basin reserves. The Gulf Coast Basin is the area where the downward revisions occurred. Such audit was conducted as of December 31, 2005 and was completed early in 2006.

•		We have adopted and distributed a written policy and guidelines for booking estimated proved reserves to all personnel involved in the reserve estimation process.

•		We have had 100% of our proved reserves fully engineered by outside engineering firms.

We intend to continue to move forward with the following remedial actions in 2006:

•		continue our formal training programs; and

•		during 2006 and thereafter, consult with our outside engineering firms on an interim basis on the original booking of significant acquisitions, extensions, discoveries and other additions.

Except as discussed above, there has not been any change in our internal control over financial reporting that occurred during our quarter ended September 30, 2006 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

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. 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. Stone has not yet been given any indication that the LDR plans to review franchise taxes for the franchise tax years 2004 and 2005.

In addition, on or about December 16, 2005, Robert Farer filed respective complaints in the United States District Court for the Western District of Louisiana (the “Federal Court”) purportedly alleging claims derivatively on behalf of Stone. Similar complaints were filed thereafter in the Federal Court by Joint Pension Fund, Local No. 164, I.B.E.W., and in the 15^th Judicial District Court, Parish of Lafayette, Louisiana (the “State Court”) by Gregory Sakhno. Stone was named as a nominal defendant and David Welch, Kenneth Beer, D. Peter Canty, James Prince, James Stone, John Laborde, Peter Barker, George Christmas, Richard Pattarozzi, David Voelker, Raymond Gary, B.J. Duplantis and Robert Bernhard were named as defendants in these actions. The State Court action purportedly alleges breach of the fiduciary duty, abuse of control, gross mismanagement, and waste of corporate assets against all defendants, and claims of unjust enrichment and insider selling against certain individual defendants. The Federal Court actions assert purported claims against all defendants for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets and unjust enrichment and claims against certain individual defendants for breach of fiduciary duty and violations of the Sarbanes-Oxley Act of 2002.

things, that Section 6.2(e) of the Merger Agreement did not limit the ability of EPL to explore and negotiate, in good faith, with respect to any Third Party Acquisition Proposals (as defined in the Merger Agreement), including the tender offer by ATS, Inc. for all of the outstanding shares of EPL stock at $23.00 per share (“ATS Offer”). The Delaware Court dismissed without prejudice the remainder of the claims raised by EPL in the Declaratory Action as not ripe for a judicial determination.

The foregoing pending actions are at an early stage and subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation and the regulatory proceedings. Accordingly, based on the current status of the litigation and inquiries, 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. Furthermore, to the extent that our insurance policies are ultimately available to cover any costs and/or liabilities resulting from these actions, they may not be sufficient to cover all costs and liabilities incurred by us and our current and former officers and directors in these regulatory and civil proceedings.

Item 6. Exhibits


		2.1 —		Agreement by and among Energy Partners, Ltd., EPL Acquisition Corp. LLC and Stone Energy Corporation dated as of October 11, 2006 (incorporated by reference to Exhibit 99.1 to the registrant’s Current Report on Form 8-K dated October 11, 2006 (File No. 001-12074)).

		*15.1 —		Letter from Ernst & Young LLP dated October 30, 2006, 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 1, 2006	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


		2.1 —		Agreement by and among Energy Partners, Ltd., EPL Acquisition Corp. LLC and Stone Energy Corporation dated as of October 11, 2006 (incorporated by reference to Exhibit 99.1 to the registrant’s Current Report on Form 8-K dated October 11, 2006 (File No. 001-12074)).

		*15.1 —		Letter from Ernst & Young LLP dated October 30, 2006, 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.