Stone Energy 10Q 2007 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2007


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

For the transition period from to

Commission file number 1-12074

STONE ENERGY CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ Noo

Indicate by check mark whether the registrant 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 filerþ Accelerated filero Non-accelerated filero

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

Yeso Noþ

As of October 30, 2007, there were 28,028,469 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, 2007 and December 31, 2006		1

Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2007 and 2006		2

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		3

Notes to Condensed Consolidated Financial Statements		4

Report of Independent Registered Public Accounting Firm		10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11

Item 3. Quantitative and Qualitative Disclosures About Market Risk		16

Item 4. Controls and Procedures		17

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		17

Item 6. Exhibits		20

Signature		21
Letter from Ernst & Young LLP
Certification of PEO Pursuant to Rule 13a-14(a)
Certification of PFO Pursuant to Rule 13a-14(a)
Certification of CEO & CFO Pursuant to Section 1350

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)


	September 30,			December 31,
	2007			2006
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents — unrestricted	$	288,395		$	58,862
Cash and cash equivalents — restricted		127,076			—
Accounts receivable		180,826			241,829
Fair value of hedging contracts		5,653			11,017
Deferred tax asset		50,318			—
Other current assets		799			965

Total current assets		653,067			312,673

Oil and gas properties – United States – full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $2,087,633 and $2,706,936, respectively		1,048,042			1,569,947
Unevaluated		140,451			173,925
Oil and gas properties – China (unevaluated)		36,726			40,553
Building and land, net		5,708			5,811
Fixed assets, net		5,879			8,302
Other assets, net		14,787			14,244
Fair value of hedging contracts		90			3,016

Total assets	$	1,904,750		$	2,128,471


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	84,770		$	120,532
Undistributed oil and gas proceeds		39,446			39,540
Fair value of hedging contracts		2,132			—
Asset retirement obligations		147,916			130,341
Deferred taxes		—			3,706
Current income taxes payable		46,500			—
Other current liabilities		14,840			16,709

Total current liabilities		335,604			310,828

Long-term debt		400,000			797,000
Deferred taxes		160,014			94,560
Asset retirement obligations		174,028			210,035
Fair value of hedging contracts		69			—
Other long-term liabilities		5,844			4,408

Total liabilities		1,075,559			1,416,831


Commitments and contingencies

Common stock		277			276
Treasury stock		(1,161	)		(1,161	)
Additional paid-in capital		510,479			502,747
Retained earnings		317,456			200,929
Accumulated other comprehensive income		2,140			8,849

Total stockholders’ equity		829,191			711,640

Total liabilities and stockholders’ equity	$	1,904,750		$	2,128,471

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

STONE ENERGY CORPORATION

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Operating revenue:
Oil production	$	100,759		$	98,340		$	305,516		$	247,375
Gas production		77,653			83,216			246,120			259,726
Derivative income, net		—			602			—			2,670

Total operating revenue		178,412			182,158			551,636			509,771


Operating expenses:
Lease operating expenses		39,476			52,403			131,072			119,825
Production taxes		1,542			3,413			8,214			11,515
Depreciation, depletion and amortization		71,096			83,038			231,275			224,214
Accretion expense		4,394			3,153			13,226			9,238
Salaries, general and administrative expenses		7,844			8,027			25,479			25,092
Incentive compensation expense		1,319			3,025			2,680			3,630
Derivative expenses, net		36			—			127			—

Total operating expenses		125,707			153,059			412,073			393,514


Gain on Rocky Mountain Region properties divestiture		(89	)		—			55,727			—


Income from operations		52,616			29,099			195,290			116,257


Other (income) expenses:
Interest expense		6,281			11,579			27,756			24,386
Interest income		(5,314	)		(847	)		(6,923	)		(1,919	)
Other income, net		(1,356	)		(1,176	)		(4,591	)		(2,764	)
Merger expense reimbursement		—			—			—			(18,200	)
Merger expenses		—			490			—			46,973
Early extinguishment of debt		592			—			592			—

Total other expenses		203			10,046			16,834			48,476


Income before taxes		52,413			19,053			178,456			67,781


Provision (benefit) for income taxes:
Current		29,000			170			46,500			170
Deferred		(10,655	)		(2,875	)		15,429			23,297

Total income taxes		18,345			(2,705	)		61,929			23,467


Net income	$	34,068		$	21,758		$	116,527		$	44,314


Basic earnings per share	$	1.23		$	0.79		$	4.22		$	1.62
Diluted earnings per share	$	1.23		$	0.79		$	4.21		$	1.62

Average shares outstanding		27,630			27,454			27,583			27,313
Average shares outstanding assuming dilution		27,722			27,619			27,669			27,429

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,
	2007			2006
Cash flows from operating activities:
Net income	$	116,527		$	44,314
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		231,275			224,214
Accretion expense		13,226			9,238
Deferred income tax provision		15,429			23,297
Gain on sale of oil and gas properties		(55,727	)		—
Settlement of asset retirement obligations		(53,668	)		—
Non-cash merger expenses, net		—			25,300
Non-cash stock compensation expense		3,342			3,234
Non-cash derivative (income) expense		127			(870	)
Early extinguishment of debt		592			—
Other non-cash expenses		1,968			1,169
Increase (decrease) in current income taxes payable		45,541			—
(Increase) decrease in accounts receivable		58,893			(46,853	)
(Increase) decrease in other current assets		(505	)		1,939
Increase (decrease) in accounts payable		(700	)		723
Increase (decrease) in other current liabilities		(1,986	)		7,587
Other		(3	)		(65	)

Net cash provided by operating activities		374,331			293,227


Cash flows from investing activities:
Investment in oil and gas properties		(194,290	)		(582,754	)
Proceeds from sale of oil and gas properties, net of expenses		571,862			(38	)
Sale of fixed assets		691			—
Investment in fixed and other assets		(1,039	)		(2,023	)

Net cash provided by (used in) investing activities		377,224			(584,815	)


Cash flows from financing activities:
Proceeds from bank borrowings		—			85,000
Repayments of bank borrowings		(172,000	)		(76,000	)
Proceeds from issuance of senior floating rate notes		—			225,000
Redemption of senior floating rate notes		(225,000	)		—
Deferred financing costs		—			(3,282	)
Net proceeds from exercise of stock options and vesting of restricted stock		2,054			9,215

Net cash provided by (used in) financing activities		(394,946	)		239,933


Net increase (decrease) in cash and cash equivalents		356,609			(51,655	)

Cash and cash equivalents, beginning of period		58,862			79,708


Cash and cash equivalents, end of period	$	415,471		$	28,053

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, 2007 and for the three and nine-month periods ended September 30, 2007 and 2006 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, 2006 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, 2006. The results of operations for the three and nine-month periods ended September 30, 2007 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 92,000 and 166,000 dilutive shares for the three months ended September 30, 2007 and 2006, respectively, and 86,000 and 116,000 dilutive shares for the nine months ended September 30, 2007 and 2006, 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 837,000 and 532,000 shares in the three months ended September 30, 2007 and 2006, respectively, and 1,010,000 and 532,000 shares in the nine months ended September 30, 2007 and 2006, respectively.

During the three months ended September 30, 2007 and 2006, approximately 74,000 and 122,000 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, 2007 and 2006, approximately 133,000 and 348,000 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 – Disposition of Assets

On June 29, 2007, we completed the sale of substantially all of our Rocky Mountain Region properties and related assets to Newfield Exploration Company in two separate transactions for a total cash consideration of $577.9 million (subject to final resolution of post-closing adjustments). At December 31, 2006, the estimated proved reserves associated with these assets totaled 182.4 billion cubic feet of natural gas equivalent (Bcfe), which represented 31% of our estimated proved oil and natural gas reserves. Sales of oil and gas properties under the full cost method of accounting are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and reserves. Since the sale of these oil and gas properties would significantly alter that relationship, we recognized a net gain on the sale of $55.7 million, computed as follows (in millions):


Proceeds from the sale	$	577.9
Add: Transfer of asset retirement and other obligations		1.7
Less: Transaction costs		(6.1	)
Carrying value of oil and gas properties		(516.1	)
Carrying value of other assets		(1.7	)

Net gain on sale	$	55.7

The carrying value of the properties sold was computed by allocating total capitalized costs within the U.S. full cost pool between properties sold and properties retained based on their relative fair values. The gain computation is subject to final resolution of post-closing adjustments.

The following is a reconciliation of 2007 year-to-date activity in our U.S. full cost center (in millions):


	Evaluated			Unevaluated
Oil and gas properties -
Balance beginning of year	$	4,276.9		$	173.9
Costs incurred year-to-date		159.6			29.6
Sale of Rocky Mountain Region properties		(1,300.9	)		(63.0	)

Balance, September 30, 2007	$	3,135.6		$	140.5


Accumulated depreciation, depletion and amortization -
Balance beginning of year		($2,706.9	)
Provision for DD&A		(228.5	)
Sale of Rocky Mountain Region properties		847.8

Balance, September 30, 2007		($2,087.6	)


Net capitalized costs	$	1,048.0

Approximately $126 million of proceeds, plus accrued interest income of $1.1 million, from the Rocky Mountain Region sale have been deposited with a Qualified Intermediary (under the terms of a Qualified Trust Agreement and Exchange Agreement) for potential reinvestment in like-kind replacement property as defined under Section 1031 of the Internal Revenue Code (IRC). We have identified qualified replacement properties for potential purchase and have until December 26, 2007 (the “Exchange Period”) to close on such properties. Compliance with these provisions provides for deferral of taxable gain on these sales proceeds (see Note 8 – Income Taxes). The Qualified Trust Agreement and the Exchange Agreement provide for certain restrictions on the use of these funds during the Exchange Period.

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 November 2, 2007:


	Zero-Premium Collars
	Natural Gas							Oil
	Daily
	Volume			Floor		Ceiling		Daily Volume		Floor		Ceiling
	(MMBtus/d)			Price		Price		(Bbls/d)		Price		Price
2007		20,000		$	7.50	$	10.40		3,000	$	60.00	$	78.35
2007		60,000			7.00		9.40		3,000		60.00		93.05
2008		30,000	*		8.00		14.05		3,000		60.00		90.20
2008									2,000		65.00		81.00
2008									3,000		70.00		110.25


*		January — March

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 income (expense) and are not reflected as revenue from oil and natural gas production.

Effective zero-premium collars increased our natural gas revenue by $7.3 million and reduced oil revenue by $0.1 million during the three months ended September 30, 2007. 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, with no impact realized on oil revenue. During the nine months ended September 30, 2007, we realized a net increase of $8.4 million in natural gas revenue and a net increase of $1.0 million in oil revenue related to our effective zero-premium collars. We realized a net increase in natural gas revenue related to our effective zero-premium collars of $25.5 million during the nine months ended September 30, 2006, with no impact realized on oil revenue.

During the quarters ended September 30, 2007 and 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 (expense) for the three and nine months ended September 30, 2007 and 2006 consists of the following:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				(In thousands)
Cash settlement on the ineffective portion of derivatives	$	—		$	786		$	—		$	1,801
Changes in fair market value of ineffective portion of derivatives		(36	)		(184	)		(127	)		869

Total derivative income (expense)		($36	)	$	602			($127	)	$	2,670

Note 5 – Long-Term Debt

Long-term debt consisted of the following at:


	September 30,		December 31,
	2007		2006
	(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 credit facility		—		172

Total long-term debt	$	400	$	797

At September 30, 2007, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $52.8 million had been issued under the facility. Effective June 29, 2007, in connection with the sale of substantially all of our Rocky Mountain Region properties, our borrowing base under the credit facility was reduced from $250 million to $85.4 million.

On November 1, 2007, we entered into a $300 million senior secured credit facility, maturing July 1, 2011, with a syndicated bank group. The new facility has an initial borrowing base of $175 million and replaces the previous $500 million credit facility. As of November 1, 2007, after accounting for the $52.8 million of letters of credit, we had $122.2 million of borrowings available under the new credit facility. 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. Under the financial covenants of our new credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a ratio of EBITDA to consolidated Net Interest, as defined in the credit agreement, for the preceding four quarterly periods of not less than 3.0 to 1.0. In addition, the new credit facility places certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases.

On August 1, 2007, we redeemed our Senior Floating Rate Notes at their face value of $225 million. We recorded a pre-tax charge of $0.6 million in the third quarter of 2007 for the early extinguishment of debt, which related to the recognition of previously deferred financing costs and unamortized discounts associated with the issuance of the notes in 2006.

Note 6 – Comprehensive Income

The following table illustrates the components of comprehensive income for the three and nine months ended September 30, 2007 and 2006:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006
				(In millions)
Net income	$	34.1		$	21.8	$	116.5		$	44.3
Other comprehensive income (loss), net of tax effect:
Adjustment for fair value accounting of derivatives		(2.1	)		4.2		(6.7	)		8.3

Comprehensive income	$	32.0		$	26.0	$	109.8		$	52.6

Note 7 – Asset Retirement Obligations

During the third quarter of 2007 and 2006, we recognized non-cash expenses of $4.4 million and $3.2 million, respectively, related to the accretion of our asset retirement obligations. For the nine-month periods ended September 30, 2007 and 2006, we recognized accretion expense of $13.2 million and $9.2 million, respectively.

The change in our asset retirement obligations during 2007 is set forth below (in millions):


	Nine Months Ended
	September 30, 2007
Asset retirement obligations as of the beginning of the period	$	340.4
Liabilities incurred		—
Liabilities settled		(53.7	)
Divestment of properties		(1.2	)
Accretion expense		13.2
Revision of estimates		23.2

Asset retirement obligations as of the end of the period, including current portion	$	321.9

Included in other long-term assets is $2.1 million of accrued hurricane insurance reimbursements attributable to asset retirement obligations estimated to be completed in time frames greater than one year.

Note 8 – Income Taxes

We adopted the provisions of FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes (“FIN 48”) on January 1, 2007. The net effect of the implementation of FIN 48 on our financial statements was immaterial. As of September 30, 2007 and December 31, 2006, we had unrecognized tax benefits of $1.2 million. All of our unrecognized tax benefits will impact our tax rate upon recognition.

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. For the quarter ended September 30, 2007, no interest or penalties were incurred related to underpayment of income taxes. As of September 30, 2007 and December 31, 2006, there were no accrued interest and penalties relating to prior periods.

The tax years 2003 through 2006 remain subject to examination by major tax jurisdictions.

We estimate that we will owe current federal income taxes for calendar year 2007 and have accrued $46.5 million through September 30, 2007 as a current liability. This estimate assumes that we will not be able to complete the acquisition of any IRC Section 1031 replacement properties. We believe it is unlikely that we will be able to successfully acquire a significant number or dollar value of the identified replacement properties within the parameters dictated by the IRC.

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, 2007			September 30, 2007
Income tax expense computed at the statutory federal income tax rate		35.0	%		35.0	%
State income taxes		—			(0.3	)

Effective income tax rate		35.0	%		34.7	%

Note 9 – International Operations

During 2006, we entered into an agreement to participate in the drilling of exploratory wells on two offshore concessions in Bohai Bay, China. After the drilling of three wells, it has been determined that additional drilling will be necessary to evaluate the commercial viability of this project. We have the potential to earn an interest in 750,000 acres on these two concessions. Included in unevaluated oil and gas property costs at September 30, 2007 are $36.7 million of capital expenditures related to our properties in Bohai Bay, China.

Note 10 — 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, 2007 no shares had been repurchased.

Note 11 — Commitments and Contingencies

On April 23, 2007, Stone received notification from the Staff of the SEC that its inquiry into the revision of Stone’s proved reserves had been terminated and no enforcement action had been recommended. In 2005, Stone had received notice that the Staff of the SEC was conducting an inquiry into the revision of Stone’s proved reserves and the financial statement restatement.

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. Additionally, in October 2007, the LDR concluded its audit of the 2004 franchise year and assessed franchise taxes of $1.5 million plus accrued interest calculated through November 2, 2007 of $0.8 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. The franchise tax years 2005 and 2006 remain subject to examination.

Stone has received an inquiry from the Philadelphia Stock Exchange investigating matters including trading prior to Stone’s October 6, 2005 announcement regarding the revision of Stone’s proved reserves. Stone cooperated fully with this inquiry.

On or around November 30, 2005, George Porch filed a putative class action in the United States District Court for the Western District of Louisiana (the “Federal Court”) against Stone, David Welch, Kenneth Beer, D. Peter Canty and James Prince purporting to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. Three similar complaints were filed soon thereafter. 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 (“Securities Action”). 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.

On August 17, 2007, a Federal Magistrate Judge issued a report and recommendation (the “Report”) recommending that the Federal Court grant in part and deny in part the Motions to Dismiss. The Report recommended that (i) the claims asserted against defendants Kenneth Beer and James Prince pursuant to Section 10(b) of the Securities Exchange Act and Rule 10b-5 promulgated thereunder and (ii) claims asserted on behalf of putative class members who sold their Company shares prior to October 6, 2005 be dismissed and that the Motions to Dismiss be denied with respect to the other claims against Stone and the individual defendants.

On October 1, 2007, the Federal Court issued an Order directing that judgment on the Motions to Dismiss be entered in accordance with the recommendations of the Report. On October 23, 2007, Stone and the individual defendants filed a motion seeking permission to appeal the denial of the Motions to Dismiss to the Fifth Circuit Court of Appeals.

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

derivative action complaint purported to allege breaches of fiduciary duty by the director defendants in connection with the then proposed merger transaction with Plains Exploration and Production Company (“Plains”) and seeks an order enjoining the director defendants from entering into the then proposed transaction with Plains. On May 15, 2006, the first consolidated complaint in the Federal Court derivative action was filed; it contained a similar injunctive claim. On September 15, 2006, co-lead plaintiffs’ in the Federal Court derivative action further amended their complaint to seek an order enjoining Stone’s proposed merger with Energy Partners, Ltd. (“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. Those motions were denied without prejudice on November 30, 2006 when the Federal Court granted the co-lead plaintiffs leave to file a third amended complaint. Following the filing of the third amended complaint in the Federal Court derivative action, defendants filed motions seeking to have that action either dismissed or stayed until resolution of the pending motion to dismiss the Securities Action before the Federal Court. On December 21, 2006 the Federal Court stayed the Federal Court derivative action at least until resolution of the then-pending motion to dismiss the Securities Action after which time a hearing will be conducted by the Federal Court to determine the propriety of maintaining that stay. As of the date hereof, the Federal Court has yet to consider any potential modification of the stay.

On or around August 28, 2006, ATS, Inc. 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. On November 2, 2006, Stone and EPL filed motions to dismiss the Farrington Action, and on September 10, 2007, the parties filed a Stipulation and Order dismissing the Farrington action without prejudice, which was granted. No compensation in any form passed from any of the defendants to plaintiff or his attorneys. The court retained jurisdiction over plaintiff’s claim for award of attorneys’ fees and reimbursement of litigation costs and expenses.

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.

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.

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, 2007, and the related condensed consolidated statement of operations for the three and nine-month periods ended September 30, 2007 and 2006, and the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. 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, 2006, 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 23, 2007, 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, 2006, 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 5, 2007

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

ThisForm 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 thisForm 10-Q should be read in conjunction with the MD&A contained in our Annual Report onForm 10-K for the year ended December 31, 2006.

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. Prior to June 29, 2007, we also had significant operations in the Rocky Mountain Region. We are also engaged in an exploratory joint venture in Bohai Bay, China. 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, and other potential areas. Throughout this document, reference to our “Gulf Coast Basin” properties includes our onshore, shelf, deep shelf and deep water properties. Reference to our “Rocky Mountain Region” includes our properties in several Rocky Mountain Basins and the Williston Basin.

On June 29, 2007, we completed the sale of substantially all of our Rocky Mountain Region properties and related assets to Newfield Exploration Company in two separate transactions for a total cash consideration of $577.9 million. At December 31, 2006, the estimated proved reserves associated with these assets totaled 182.4 billion cubic feet of gas equivalent (Bcfe), which represented 31% of our estimated proved oil and natural gas reserves. The divested properties included our interests in the Pinedale Anticline, the Jonah field, the Williston Basin, the Scott field and several smaller producing areas. The sale also included net undeveloped acreage of approximately 550,000 acres. We maintained a 35% proportional working interest in several undeveloped plays in the Rocky Mountain region totaling approximately 60,000 acres.

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;

	•		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 our Annual Report on Form 10-K regarding these other risk factors.

Known Trends and Uncertainties

International Operations.Included in unevaluated oil and gas property costs at September 30, 2007 are $36.7 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 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.

Taxable Gain.Approximately $126 million of proceeds, plus accrued interest income of $1.1 million, from the Rocky Mountain Region sale have been deposited with a Qualified Intermediary (under the terms of a Qualified Trust Agreement and Exchange Agreement) for potential reinvestment in like-kind replacement property as defined under Section 1031 of the Internal Revenue Code (IRC). We have identified qualified replacement properties for potential purchase and have until December 26, 2007 (the “Exchange Period”) to close on such properties. Compliance with these provisions provides for deferral of taxable gain on these sales proceeds. Our estimate of current taxes payable assumes we will not be able to complete the acquisition of any IRC 1031 replacement properties within the parameters dictated by the IRC. We believe it is unlikely that we will be able to successfully acquire a significant number or dollar value of the identified replacement properties within the parameters dictated by the IRC.

Liquidity and Capital Resources

Cash Flow and Working Capital.Net cash flow provided by operating activities for the nine months ended September 30, 2007 was $374.3 million compared to $293.2 million generated in the comparable period in 2006.

Net cash flow provided by investing activities totaled $377.2 million during the first nine months of 2007, which primarily represents proceeds received from the sale of substantially all of our Rocky Mountain Region properties offset by our investment in oil and natural gas properties. Net cash flow used in investing activities during the first nine months of 2006 totaled $584.8 million, which primarily represents our investment in oil and natural gas properties. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2007 capital expenditures (excluding acquisitions) with cash flow from operating activities.

Net cash flow used in financing activities totaled $394.9 million for the nine months ended September 30, 2007, which primarily represents the redemption of our senior floating rate notes and repayments of borrowings under our credit facility. 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.

Of the total proceeds received on the sale of our Rocky Mountain Region properties, $126 million related to the Jonah field and such amount has been deposited with a qualified intermediary for potential reinvestment in like-kind exchange transactions under IRC 1031. This amount, along with $1.1 million of interest income earned through September 30, 2007, is classified as restricted cash on our balance sheet.

We had working capital at September 30, 2007 of $317.5 million. A substantial portion of this working capital was generated from the sale of our Rocky Mountain Region properties on June 29, 2007. 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 of assets or incurrence of liabilities. See“Bank Credit Facility”.

Capital Expenditures.Third quarter 2007 additions to oil and gas property costs of $29.6 million, included $0.9 million of acquisition costs, $4.8 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $3.3 million of capitalized interest. Year-to-date 2007 additions to oil and gas property costs of $185.4 million, included $9.2 million of acquisition costs, $23.2 million of asset retirement costs, $14.6 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $12.7 million of capitalized interest. These investments were financed by cash flow from operating activities.

Our 2007 capital expenditures budget, which excludes acquisitions, hurricane related asset retirement costs and capitalized interest and salaries, general and administrative expenses, is approximately $290 million. The budget was adjusted downward from $320 million upon the sale of substantially all of our Rocky Mountain Region properties. Based upon our outlook of commodity prices and our estimated production, we expect to fund our 2007 capital program with cash flow provided by operating activities. If cash flow from operating activities during 2007 is not sufficient to fund estimated 2007 capital expenditures, we believe that our existing cash balances and our bank credit facility will provide us with adequate liquidity. See“Bank Credit Facility”.

Bank Credit Facility.At September 30, 2007, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $52.8 million had been issued under the facility. Effective June 29, 2007, in connection with the sale of substantially all of our Rocky Mountain Region properties, our borrowing base under the credit facility was reduced from $250 million to $85.4 million. On November 1, 2007, we entered into a $300 million senior secured credit facility, maturing on July 1, 2011, with a syndicated bank group. The new facility has an initial borrowing base of $175 million and replaces the previous $500 million credit facility. As of November 1, 2007, after accounting for the $52.8 million of letters of credit, we had $122.2 million of borrowings available under the new credit facility. 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.

$225 Million Senior Floating Rate Notes.On August 1, 2007, we redeemed our Senior Floating Rate Notes at their face value of $225 million. We recorded a pre-tax charge of $0.6 million in the third quarter of 2007 for the early extinguishment of debt, which related to the recognition of previously deferred financing costs and unamortized discounts associated with the issuance of the notes in 2006.

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, 2007 no shares had been repurchased.

Results of Operations

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


	Three Months Ended
	September 30,
	2007		2006		Variance			% Change
Production:
Oil (MBbls)		1,313		1,465		(152	)		(10	%)
Natural gas (MMcf)		10,801		10,971		(170	)		(2	%)
Oil and natural gas (MMcfe)		18,679		19,761		(1,082	)		(5	%)
Revenue data (in thousands) (a):
Oil revenue	$	100,759	$	98,340	$	2,419			2	%
Natural gas revenue		77,653		83,216		(5,563	)		(7	%)

Total oil and natural gas revenue	$	178,412	$	181,556		($3,144	)		(2	%)
Average prices (a):
Oil (per Bbl)	$	76.74	$	67.13	$	9.61			14	%
Natural gas (per Mcf)		7.19		7.59		(0.40	)		(5	%)
Oil and natural gas (per Mcfe)		9.55		9.19		0.36			4	%
Expenses (per Mcfe):
Lease operating expenses	$	2.11	$	2.65		($0.54	)		(20	%)
Salaries, general and administrative expenses (b)		0.42		0.41		0.01			2	%
DD&A expense on oil and gas properties		3.76		4.15		(0.39	)		(9	%)


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

(b)		Exclusive of incentive compensation expense.


	Nine Months Ended
	September 30,
	2007		2006		Variance			% change
Production:
Oil (MBbls)		4,691		3,803		888			23	%
Natural gas (MMcf)		34,109		33,139		970			3	%
Oil and natural gas (MMcfe)		62,255		55,957		6,298			11	%
Revenue data (in thousands) (a):
Oil revenue	$	305,516	$	247,375	$	58,141			24	%
Natural gas revenue		246,120		259,726		(13,606	)		(5	%)

Total oil and natural gas revenue	$	551,636	$	507,101	$	44,535			9	%
Average prices (a):
Oil (per Bbl)	$	65.13	$	65.05	$	0.08			0	%
Natural gas (per Mcf)		7.22		7.84		(0.62	)		(8	%)
Oil and natural gas (per Mcfe)		8.86		9.06		(0.20	)		(2	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.11	$	2.14		($0.03	)		(1	%)
Salaries, general and administrative expenses (b)		0.41		0.45		(0.04	)		(9	%)
DD&A expense on oil and gas properties		3.67		3.96		(0.29	)		(7	%)


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

(b)		Exclusive of incentive compensation expense.

During the third quarter of 2007, net income totaled $34.1 million, or $1.23 per share, compared to $21.8 million, or $0.79 per share for the third quarter of 2006. For the nine months ended September 30, 2007, net income totaled $116.5 million, or $4.21 per share, compared to $44.3 million, or $1.62 per share, during the comparable 2006 period. All per share amounts are on a diluted basis.

Included in the nine month 2007 net income is a $55.7 million gain ($36.3 million net of tax) on the sale of our Rocky Mountain Region properties, representing the excess of the proceeds from the sale over the carrying value of the oil and gas properties and other assets sold and transaction costs.

Included in year-to-date 2006 net income is a $43.5 million termination fee incurred in connection with the proposed merger with Energy Partners, Ltd. (“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 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 was recognized in earnings in the fourth quarter of 2006. Additionally, the remaining $25.3 million of the Plains Termination Fee was 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:

Production.During the third quarter of 2007, total production volumes decreased 5% to 18.7 Bcfe compared to 19.8 Bcfe produced during the third quarter of 2006. Oil production during the third quarter of 2007 totaled approximately 1,313,000 barrels compared to 1,465,000 barrels produced during the third quarter of 2006, while natural gas production totaled 10.8 Bcf during the third quarter of 2007 compared to 11.0 Bcf produced during the third quarter of 2006. Year-to-date 2007 production totaled 4,691,000 barrels of oil and 34.1 Bcf of natural gas compared to 3,803,000 barrels of oil and 33.1Bcf of natural gas produced during the comparable 2006 period.

Extended Gulf Coast production shut-ins due to Hurricanes Katrina and Rita negatively impacted third quarter 2007 and 2006 production rates resulting in production deferrals of 0.9 Bcfe (10 MMcfe per day) and 3.4 Bcfe (37 MMcfe per day), respectively. Production deferrals due to hurricanes for the nine months ended September 30, 2007 and 2006 amounted to 3.1 Bcfe (17 MMcfe per day) and 14.2 Bcfe (52 MMcfe per day), respectively. Without the effects of production deferrals, quarter-to-date and year-to-date 2007 production volumes decreased approximately 3.6 Bcfe and 4.8 Bcfe, respectively, from quarter-to-date and year-to-date 2006 production volumes. These decreases were primarily the result of the sale of substantially all of our Rocky Mountain Region properties

on June 29, 2007. Rocky Mountain Region production was 3.0 Bcfe for the three months ended September 30, 2006 and 6.6 Bcfe and 9.0 Bcfe for the nine months ended September 30, 2007 and 2006, respectively.

Prices. Prices realized during the third quarter of 2007 averaged $76.74 per Bbl of oil and $7.19 per Mcf of natural gas, or 4% higher, on an Mcfe basis, than third quarter 2006 average realized prices of $67.13 per Bbl of oil and $7.59 per Mcf of natural gas. Average realized prices during the first nine months of 2007 were $65.13 per Bbl of oil and $7.22 per Mcf of natural gas compared to $65.05 per Bbl of oil and $7.84 per Mcf of natural gas realized during the first nine months of 2006. 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. During the third quarter of 2007, our effective hedging transactions increased our average realized natural gas prices by $0.68 per Mcf. Hedging transactions for natural gas during the first nine months of 2007 increased the average price we received for natural gas by $0.25 per Mcf. Natural gas prices realized during the three and nine month periods of 2006 were increased by $1.05 and $0.77 per Mcf, respectively, as a result of effective hedging transactions. During the third quarter of 2007, our effective hedging transactions decreased our average realized oil prices by $0.09 per Bbl. Hedging transactions for oil during the first nine months of 2007 increased the average price we received for oil by $0.21 per Bbl. Hedging transactions did not impact realized oil prices during the three or nine month periods of 2006.

Income.Third quarter 2007 oil and natural gas revenue totaled $178.4 million, compared to third quarter 2006 oil and natural gas revenue of $181.6 million. The decrease is attributable to a slight decrease in oil and natural gas production volumes. Year-to-date 2007 oil and natural gas revenue totaled $551.6 million compared to $507.1 million during the comparable 2006 period primarily due to an increase in oil and natural gas production volumes slightly offset by a decline in oil and natural gas prices. Rocky Mountain Region year-to-date 2007 oil and natural gas revenue amounted to $47.1 million, representing 9% of total company oil and natural gas revenue for the nine months ended September 30, 2007.

Interest income totaled $5.3 million during the third quarter of 2007 compared to $0.8 million during the comparable quarter of 2006. For the first nine months of 2007 and 2006, interest income totaled $6.9 million and $1.9 million, respectively. The increase in interest income is the result of an increase in our cash balances during the period after the sale of substantially all of our Rocky Mountain Region properties in June 2007.

Expenses.Lease operating expenses during the third quarter of 2007 totaled $39.5 million compared to $52.4 million for the third quarter of 2006. Third quarter 2006 lease operating expenses included approximately $9.7 million of repairs in excess of insurance recoveries related to damage from Hurricanes Katrina, Rita and Ivan and increased major maintenance repair activity. The decrease in lease operating expenses in the third quarter of 2007 compared to 2006 was also the result of the sale of substantially all of our Rocky Mountain Region properties on June 29, 2007. Rocky Mountain Region lease operating expenses during the third quarter of 2006 totaled $3.2 million. For the first nine months of 2007, lease operating expenses totaled $131.1 million, an increase of 9% over the $119.8 million of lease operating expenses for the comparable period in 2006. For the nine months ended September 30, 2007, lease operating expenses included an increase in insurance premiums and an increase in overall industry service costs. Rocky Mountain Region lease operating expenses were $8.6 million and $8.0 million for the nine months ended September 30, 2007 and 2006, respectively.

Depreciation, depletion and amortization (“DD&A”) on oil and gas properties for the third quarter of 2007 totaled $70.3 million, or $3.76 per Mcfe compared to $82.0 million or $4.15 per Mcfe for the third quarter of 2006. For the nine months ended September 30, 2007 and 2006, DD&A expense totaled $228.5 million and $221.3 million, respectively. At December 31, 2006, we recorded a ceiling test write-down, which reduced our net investment in oil and gas properties and resulted in a reduction of the going forward unit cost of DD&A of $0.86 per Mcfe.

Salaries, general and administrative (SG&A) expenses (exclusive of incentive compensation) for the third quarter of 2007 were $7.8 million compared to $8.0 million in the third quarter of 2006. For the nine months ended September 30, 2007 and 2006, SG&A totaled $25.5 million and $25.1 million, respectively. Included in year-to-date 2007 SG&A are severance and retention payments of $2.1 million made to employees in our Denver District in connection with the sale of substantially all of our Rocky Mountain Region properties and the resulting discontinuation of operations of such district. Total year-to-date SG&A expense for the Denver District was $3.8 million. Exclusive of the $2.1 million severance and retention payments, year-to-date Denver District SG&A represented 7% of total company SG&A.

Incentive compensation expense for the third quarter of 2007 was $1.3 million compared to $3.0 million in the third quarter of 2006. Year-to-date 2007 and 2006 incentive compensation expense totaled $2.7 million and $3.6 million, respectively. Third quarter and year-to-date 2006 incentive compensation expense included a 100% incentive compensation accrual which resulted from an employee retention program put in place by our board of directors in the third quarter of 2006. Incentive compensation expense for 2007 does not include amounts for our Denver District which was discontinued in June 2007 after the sale of substantially all of our Rocky Mountain Region properties.

Interest expense for the third quarter of 2007 totaled $6.3 million, net of $3.3 million of capitalized interest, compared to interest expense of $11.6 million, net of $4.9 million of capitalized interest, during the third quarter of 2006. The decrease in interest expense for the third quarter of 2007 compared to the comparable quarter of 2006 was a result of the pay down of all outstanding borrowings under our bank credit facility in June 2007 and the redemption of our Senior Floating Rate Notes in August 2007 with

proceeds received from the sale of substantially all of our Rocky Mountain Region properties. For the nine months ended September 30, 2007, interest expense totaled $27.8 million, net of capitalized interest of $12.7 million, compared to interest expense of $24.4 million, net of $13.4 million of capitalized interest, during the nine months ended September 30, 2006, respectively.

During the three months ended September 30, 2007 and 2006, we incurred $4.4 and $3.2 million, respectively, of accretion expense related to asset retirement obligations. Year-to-date 2007 and 2006 accretion expense totaled $13.2 million and $9.2 million, respectively. The increase in 2007 accretion expense is due to increases in estimated asset retirement costs determined in late 2006.

During the year-to-date periods ended September 30, 2007 and 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. The change in the fair market value of the ineffective portion of these derivatives for the quarter ended September 30, 2007 was $36,000 and was recognized as derivative expense in the income statement. For the nine months ended September 30, 2007, the change in the fair market value of the ineffective portion of these derivatives was $0.1 million of net derivative expense. 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.

Production taxes during the third quarter of 2007 totaled $1.5 million compared to $3.4 million in the third quarter of 2006. For the nine months ended September 30, 2007 and 2006, production taxes totaled $8.2 million and $11.5 million, respectively. The decrease in production taxes resulted from of the sale of substantially all of our Rocky Mountain Region properties in June 2007. Year-to-date 2007 Rocky Mountain Region production taxes totaled $4.0 million, representing 49% of total company production taxes for such period.

We estimate that current Federal income taxes for calendar year 2007 will amount to approximately $62.0 million and have accrued $46.5 million through September 30, 2007 as a current liability and current income tax provision. This assumes that we will not be able to complete the acquisition of an IRC Section 1031 replacement property within the parameters dictated by the IRC.

Recent Accounting Developments

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.

The Fair Value Option for Certain Items.In February of 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Liabilities – Including an amendment of FASB Statement No. 115”. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement will be effective for us January 1, 2008.

We do not anticipate that the implementation of these new standards will have a material effect on our financial statements.

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 50% of our estimated 2007 production

and 25% of our estimated 2008 production. SeeItem 1. Financial Statements – Note 4 – Hedging Activitiesfor a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 2006 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

We had long-term debt outstanding of $400 million at September 30, 2007, all of which bears interest at fixed rates. The $400 million of fixed-rate debt is comprised of $200 million of 8¹/4% Senior Subordinated Notes due 2011 and $200 million of 6³/4% Senior Subordinated Notes due 2014. On August 1, 2007, we redeemed in full our $225 million Senior Floating Rate Notes at face value with a portion of the proceeds received from the sale of our Rocky Mountain Region properties. Borrowings under our bank credit facility were paid in full on June 29, 2007 in connection with the sale of our Rocky Mountain Region properties. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates.

Since the filing of our 2006 Annual Report on Form 10-K, market risk as it relates to interest rates has been mitigated with the redemption of our senior floating rate notes and the reduction in outstanding balances on our credit facility.

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 subsidiary (collectively “Stone”) is made known to the Officers who certify Stone’s financial reports and the Board of Directors. 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 chief executive officer and our chief 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, 2007. Based on this evaluation, our chief executive officer and chief financial officer believe:

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

	•		Stone’s disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports that it files or submits under the Securities Exchange Act of 1934 was accumulated and communicated to Stone’s management, including Stone’s chief executive officer and chief 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 our quarterly period ended September 30, 2007 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 taxes of $1.5 million plus accrued interest calculated through November 2, 2007 of $0.8 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. The franchise tax years 2005 and 2006 remain subject to examination.

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 purported to allege breaches of fiduciary duty by the director defendants in connection with the then proposed merger transaction with Plains Exploration and Production Company (“Plains”) and seeks an order enjoining the director defendants from entering into the then proposed transaction with Plains. On May 15, 2006, the first consolidated complaint in the Federal Court derivative action was filed; it contained a similar injunctive claim. On September 15, 2006, co-lead plaintiffs’ in the Federal Court derivative action further amended their complaint to seek an order enjoining Stone’s proposed merger with Energy Partners, Ltd. (“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. Those motions were denied without prejudice on November 30, 2006 when the Federal Court granted the co-lead plaintiffs leave to file a third amended complaint. Following the filing of the third amended complaint in the Federal Court derivative action, defendants filed motions seeking to have that action either dismissed or stayed until resolution of the pending motion to dismiss the Securities Action before the Federal Court. On December 21, 2006 the Federal Court stayed the Federal Court derivative action at least until resolution of the then-pending motion to dismiss the Securities Action after which time a hearing will be conducted by the Federal Court to determine the propriety of maintaining that stay. As of the date hereof, the Federal Court has yet to consider any potential modification of the stay.

Item 6. Exhibits


10.1 –		Credit Agreement between the Registrant, the financial institutions named therein and Bank of America, N.A., as administrative agent, dated November 1, 2007 (incorporated by reference to exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated November 1, 2007 (File No. 001-12074)).

*15.1 –		Letter from Ernst & Young LLP dated November 5, 2007, 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 6, 2007	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


10.1 –		Credit Agreement between the Registrant, the financial institutions named therein and Bank of America N.A., as administrative agent, dated November 1, 2007 (incorporated by reference to the Registrant’s Current Report on Form 8-K dated November 1, 2007 (File No. 001-12074)).

*15.1 –		Letter from Ernst & Young LLP dated November 5, 2007, 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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Stone Energy (SGY) 10-Q2007 Q3 Quarterly report

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