STONE ENERGY CORP - FORM 10-Q

STONE ENERGY CORP - FORM 10-Q - November 6, 2014

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2014

¨	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		70508
(Address of principal executive offices)		(Zip Code)

(337) 237-0410

(Registrant’s telephone number, including area code)

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of November 3, 2014, there were 56,175,414 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, 2014 and December 31, 2013		1

	Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2014 and 2013		2

	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2014 and 2013		3

	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2014 and 2013		4

	Notes to Condensed Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		31

Item 4.	Controls and Procedures		32

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		33

Item 1A.	Risk Factors		34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34

Item 6.	Exhibits		35

	Signatures		36

	Exhibit Index		37

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	September 30,			December 31,
	2014			2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	180,307		$	331,224
Restricted cash		177,647			—
Accounts receivable		173,775			171,971
Fair value of derivative contracts		16,635			4,549
Current income tax receivable		7,373			7,366
Deferred taxes		24,036			31,710
Inventory		3,709			3,723
Other current assets		1,884			1,874

Total current assets		585,366			552,417
Oil and gas properties, full cost method of accounting:
Proved		8,692,017			7,804,117
Less: accumulated depreciation, depletion and amortization		(6,568,551	)		(5,908,760	)

Net proved oil and gas properties		2,123,466			1,895,357
Unevaluated		570,658			724,339
Other property and equipment, net		32,118			26,178
Fair value of derivative contracts		6,481			1,378
Other assets, net		40,860			48,887

Total assets	$	3,358,949		$	3,248,556

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	121,485		$	195,677
Undistributed oil and gas proceeds		58,503			37,029
Accrued interest		22,240			9,022
Fair value of derivative contracts		156			7,753
Asset retirement obligations		73,451			67,161
Other current liabilities		57,630			54,520

Total current liabilities		333,465			371,162
Long-term debt		1,037,440			1,027,084
Deferred taxes		394,846			390,693
Asset retirement obligations		336,197			435,352
Fair value of derivative contracts		24			470
Other long-term liabilities		41,350			53,509

Total liabilities		2,143,322			2,278,270

Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 54,882,808 and 48,750,533 shares, respectively		549			488
Treasury stock (16,582 shares, at cost)		(860	)		(860	)
Additional paid-in capital		1,628,942			1,397,885
Accumulated deficit		(424,193	)		(425,165	)
Accumulated other comprehensive income (loss)		11,189			(2,062	)

Total stockholders’ equity		1,215,627			970,286

Total liabilities and stockholders’ equity	$	3,358,949		$	3,248,556

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

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Operating revenue:
Oil production	$	123,795		$	186,608		$	404,477		$	558,031
Gas production		30,154			52,728			133,183			137,382
Natural gas liquids production		21,014			16,476			64,920			36,854
Other operational income		2,468			873			5,515			2,659
Derivative income, net		5,782			—			2,667			—

Total operating revenue		183,213			256,685			610,762			734,926

Operating expenses:
Lease operating expenses		43,561			53,986			139,918			157,547
Transportation, processing and gathering expenses		16,721			13,081			45,445			27,374
Production taxes		3,651			5,224			9,970			11,404
Depreciation, depletion and amortization		80,291			92,853			255,772			255,497
Write-down of oil and gas properties		47,130			—			47,130			—
Accretion expense		6,539			8,431			21,827			25,012
Salaries, general and administrative expenses		16,286			14,201			49,252			43,351
Incentive compensation expense		3,092			4,566			10,129			8,047
Other operational expenses		298			237			510			382
Derivative expense, net		—			1,684			—			1,537

Total operating expenses		217,569			194,263			579,953			530,151

Income (loss) from operations		(34,356	)		62,422			30,809			204,775

Other (income) expenses:
Interest expense		10,323			7,922			28,593			26,452
Interest income		(169	)		(1,311	)		(505	)		(1,543	)
Other income		(695	)		(782	)		(2,124	)		(2,190	)
Other expense		95			—			274			—

Total other expenses		9,554			5,829			26,238			22,719

Income (loss) before income taxes		(43,910	)		56,593			4,571			182,056

Provision (benefit) for income taxes:
Current		—			(88	)		—			(10,827	)
Deferred		(14,495	)		20,579			3,599			77,001

Total income taxes		(14,495	)		20,491			3,599			66,174

Net income (loss)	($	29,415	)	$	36,102		$	972		$	115,882

Basic earnings (loss) per share	($	0.54	)	$	0.72		$	0.02		$	2.32
Diluted earnings (loss) per share	($	0.54	)	$	0.72		$	0.02		$	2.32
Average shares outstanding		54,866			48,732			51,998			48,680
Average shares outstanding assuming dilution		54,866			48,776			52,139			48,720

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income (loss)	($	29,415	)	$	36,102		$	972		$	115,882
Other comprehensive income (loss), net of tax effect:
Derivatives		30,975			(18,384	)		14,620			(22,164	)
Foreign currency translation		(1,625	)		267			(1,369	)		(256	)

Comprehensive income (loss)	($	65	)	$	17,985		$	14,223		$	93,462

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2014			2013
Cash flows from operating activities:
Net income	$	972		$	115,882
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		255,772			255,497
Write-down of oil and gas properties		47,130			—
Accretion expense		21,827			25,012
Deferred income tax provision		3,599			77,001
Settlement of asset retirement obligations		(47,217	)		(61,178	)
Non-cash stock compensation expense		8,409			7,583
Excess tax benefits		—			(156	)
Non-cash derivative (income) expense		(2,386	)		1,626
Non-cash interest expense		12,393			12,384
Change in current income taxes		(6	)		(704	)
Increase in accounts receivable		(1,805	)		(22,277	)
(Increase) decrease in other current assets		(10	)		2,187
Decrease in inventory		—			158
Increase (decrease) in accounts payable		(3,547	)		8,035
Increase in other current liabilities		37,441			20,251
Other		(172	)		(1,791	)

Net cash provided by operating activities		332,400			439,510

Cash flows from investing activities:
Investment in oil and gas properties		(727,488	)		(472,304	)
Proceeds from sale of oil and gas properties, net of expenses		223,299			6,300
Investment in fixed and other assets		(8,790	)		(3,830	)
Change in restricted funds		(185,752	)		(2,394	)

Net cash used in investing activities		(698,731	)		(472,228	)

Cash flows from financing activities:
Net proceeds from issuance of common stock		225,999			—
Deferred financing costs		(3,329	)		(11	)
Excess tax benefits		—			156
Net payments for share-based compensation		(7,161	)		(3,733	)

Net cash provided by (used in) financing activities		215,509			(3,588	)

Effect of exchange rate changes on cash		(95	)		(145	)

Net change in cash and cash equivalents		(150,917	)		(36,451	)
Cash and cash equivalents, beginning of period		331,224			279,526

Cash and cash equivalents, end of period	$	180,307		$	243,075

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Interim Financial Statements

The condensed consolidated financial statements of Stone Energy Corporation (“Stone”) and its subsidiaries as of September 30, 2014 and for the three and nine month periods ended September 30, 2014 and 2013 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 as of December 31, 2013 has been derived from the audited financial statements as of that date contained in our Annual Report on Form 10-K for the year ended December 31, 2013 (our “2013 Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our 2013 Annual Report on Form 10-K. The results of operations for the three and nine month periods ended September 30, 2014 are not necessarily indicative of future financial results.

Note 2 – Earnings Per Share

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands, except per share data)
Income (numerator):
*Basic:*
Net income (loss)	($	29,415	)	$	36,102		$	972		$	115,882
Net income attributable to participating securities		—			(924	)		(22	)		(2,728	)

Net income (loss) attributable to common stock—basic	($	29,415	)	$	35,178		$	950		$	113,154

*Diluted:*
Net income (loss)	($	29,415	)	$	36,102		$	972		$	115,882
Net income attributable to participating securities		—			(923	)		(22	)		(2,726	)

Net income (loss) attributable to common stock—diluted	($	29,415	)	$	35,179		$	950		$	113,156

Weighted average shares (denominator):
Weighted average shares—basic		54,866			48,732			51,998			48,680
Dilutive effect of stock options		—			44			53			40
Dilutive effect of convertible notes		—			—			88			—

Weighted average shares—diluted		54,866			48,776			52,139			48,720

Basic earnings (loss) per share	($	0.54	)	$	0.72		$	0.02		$	2.32

Diluted earnings (loss) per share	($	0.54	)	$	0.72		$	0.02		$	2.32

All outstanding stock options were considered antidilutive during the three months ended September 30, 2014 (205,000 shares) because we had a net loss for such period. Stock options that were considered antidilutive because the exercise price of the options exceeded the average price of our common stock for the applicable period totaled approximately 116,000 shares during the nine months ended September 30, 2014 and 327,000 shares during the three and nine months ended September 30, 2013.

During the three months ended September 30, 2014 and 2013, approximately 10,000 shares and 22,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock by employees and nonemployee directors. During the nine months ended September 30, 2014 and 2013, approximately 382,000 shares and 358,000 shares of common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and the exercise of stock options by employees and nonemployee directors. In May 2014, 5,750,000 shares of our common stock were issued in a public offering (see Note 3 – Common Stock Offering).

Because it is management’s stated intention to redeem the principal amount of our 1³⁄₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) (see Note 5 – Long-Term Debt) in cash, we have used the treasury method for determining dilution in the diluted earnings per share computation. Since the average price of our common stock was less than the effective conversion price for such notes during the three months ended September 30, 2014, and because we had a net loss for such period, the 2017 Convertible Notes were not dilutive for such period. During the three months ended June 30, 2014, the average price of our common stock exceeded the effective conversion price of the 2017 Convertible Notes and had a dilutive impact on the diluted earnings per share computation for the nine months ended September 30, 2014. For the prior year periods presented, the average price of our common stock was less than the effective conversion price for such notes, resulting in no dilutive effect on the diluted earnings per share computation for such periods. For all periods presented, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 5 – Long-Term Debt) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 5 – Long-Term Debt), such call options are antidilutive and therefore, were not included in the calculation of diluted earnings per share.

Note 3 – Common Stock Offering

In May 2014, we sold 5,750,000 shares of our common stock in a public offering at a price of $41.00 per share resulting in net proceeds of approximately $226.0 million after deducting the underwriting discount and offering expenses.

Note 4 – Derivative Instruments and Hedging Activities

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.

The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, 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 stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2014, 2015 and 2016 oil and natural gas production from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate crude oil during the entire calendar month, and some are based on the average of the Intercontinental Exchange closing price for Brent crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America, Natixis and Regions Bank.

The following table illustrates our derivative positions for calendar years 2014, 2015 and 2016 as of November 3, 2014:


	Fixed-Price Swaps (NYMEX, except where noted)
	Natural Gas					Oil
	Daily Volume (MMBtus/d)			Swap Price ($)		Daily Volume (Bbls/d)			Swap Price ($)
2014		10,000			4.000		1,000			90.06
2014		10,000			4.040		1,000	(a)		90.25
2014		10,000			4.105		1,000			92.25
2014		10,000			4.190		1,000			93.55
2014		10,000	(b)		4.250		1,000			94.00
2014		10,000			4.250		1,000			98.00
2014		10,000			4.350		1,000			98.30
2014							2,000	(c)		98.85
2014							1,000			99.65
2014							1,000	(d)		103.30
2015		10,000			4.005		1,000			89.00
2015		10,000			4.120		1,000			90.00
2015		10,000			4.150		1,000			90.25
2015		10,000			4.165		1,000			90.40
2015		10,000			4.220		1,000			91.05
2015		10,000			4.255		1,000			93.28
2015							1,000			93.37
2015							1,000			94.85
2015							1,000			95.00
2016		10,000			4.110		1,000			90.00
2016		10,000			4.120

(a)	October through December

(b)	February through December

(c)	January through June

(d)	Brent crude oil contract

All of our derivative instruments at December 31, 2013 were designated as effective cash flow hedges. At June 30, 2014, certain of our natural gas derivative instruments no longer qualified as cash flow hedges, as it was no longer probable, subsequent to the sale of our non-core Gulf of Mexico (“GOM”) conventional shelf properties (see Note 7 – Divestitures), that GOM natural gas production would be sufficient to cover the GOM volumes hedged. We discontinued hedge accounting for such contracts as of June 30, 2014. Contracts no longer qualifying as cash flow hedges were comprised of three natural gas contracts for the months of August through December 2014 and two natural gas contracts for the months of January through December 2015. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. At September 30, 2014, we had accumulated other comprehensive income of $13.2 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of September 30, 2014. We believe that approximately $9.3 million, net of tax, of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

Derivatives qualifying as hedging instruments:

The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at September 30, 2014 and December 31, 2013:


Fair Value of Derivatives Qualifying as Hedging Instruments at September 30, 2014
(In millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	15.4	Current liabilities: Fair value of derivative contracts	$	0.2
	Long-term assets: Fair value of derivative contracts		6.3	Long-term liabilities: Fair value of derivative contracts		—

		$	21.7		$	0.2


Fair Value of Derivatives Qualifying as Hedging Instruments at December 31, 2013
(In millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	4.5	Current liabilities: Fair value of derivative contracts	$	7.8
	Long-term assets: Fair value of derivative contracts		1.4	Long-term liabilities: Fair value of derivative contracts		0.5

		$	5.9		$	8.3

The following tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and nine month periods ended September 30, 2014 and 2013:


Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Three Months Ended September 30, 2014 and 2013 (In millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives					Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)							Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2014		2013			Location	2014			2013			Location	2014		2013
Commodity contracts	$	47.1	($	30.8	)	Operating revenue—oil/gas production	($	1.3	)	($	2.1	)	Derivative (expense) income, net	$	2.1	($	1.7	)

Total	$	47.1	($	30.8	)		($	1.3	)	($	2.1	)		$	2.1	($	1.7	)

(a)

For the three months ended September 30, 2014, effective hedging contracts decreased oil revenue by $1.3 million and had a minimal effect on gas revenue. For the three months ended September 30, 2013, effective hedging contracts decreased oil revenue by $7.5 million and increased gas revenue by $5.4 million.


Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Nine Months Ended September 30, 2014 and 2013 (In millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives					Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)						Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2014		2013			Location	2014			2013		Location	2014		2013
Commodity contracts	$	3.7	($	20.9	)	Operating revenue—oil/gas production	($	17.6	)	$	13.8	Derivative (expense) income, net	$	0.5	($	1.5	)

Total	$	3.7	($	20.9	)		($	17.6	)	$	13.8		$	0.5	($	1.5	)

(a)

For the nine months ended September 30, 2014, effective hedging contracts decreased oil revenue by $10.0 million and decreased gas revenue by $7.6 million. For the nine months ended September 30, 2013, effective hedging contracts increased oil revenue by $2.4 million and increased gas revenue by $11.4 million.

Derivatives not qualifying as hedging instruments:

The following table discloses the location and fair value amounts of our derivatives not qualifying as hedging instruments, as reported in our balance sheet, at September 30, 2014. All of our derivatives at December 31, 2013 qualified as hedging instruments.


Fair Value of Derivatives Not Qualifying as Hedging Instruments at September 30, 2014 (In millions)
Description	Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	1.2
	Long-term assets: Fair value of derivative contracts		0.2

		$	1.4

Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the three and nine month periods ended September 30, 2014:


Amount of Gain Recognized in Derivative Income (In millions)
Description	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Commodity contracts:
Cash settlements	$	0.7	$	0.7
Change in fair value		3.0		1.5

Total gains on non-qualifying hedges	$	3.7	$	2.2

Offsetting of derivative assets and liabilities:

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following presents the potential impact of the rights of offset associated with our recognized assets and liabilities at September 30, 2014 (in millions):


	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	16.6		($	0.2	)	$	16.4
Long-term assets: Fair value of derivative contracts		6.5			—			6.5
Current liabilities: Fair value of derivative contracts		(0.2	)		0.2			—
Long-term liabilities: Fair value of derivative contracts		—			—			—

Note 5 – Long-Term Debt

Long-term debt consisted of the following at:


	September 30, 2014		December 31, 2013
	(In millions)
1³⁄₄% Senior Convertible Notes due 2017	$	262.4	$	252.1
7¹⁄₂% Senior Notes due 2022		775.0		775.0
Bank debt		—		—

Total long-term debt	$	1,037.4	$	1,027.1

Bank Debt. On June 24, 2014, we entered into an amended and restated revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019. Our initial borrowing base under the bank credit facility was set at $500 million and was reaffirmed at $500 million in October 2014. As of September 30, 2014 and November 3, 2014, we had no outstanding borrowings under the bank credit facility and $19.2 million in letters of credit had been issued pursuant to the bank credit facility, leaving $480.8 million of availability under the bank credit facility. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. The bank credit facility is guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

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

Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“LIBOR”) rate or the base rate, at the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. The bank credit facility provides for optional and mandatory prepayments and affirmative and negative covenants, including interest coverage ratio and leverage ratio maintenance covenants. We were in compliance with all covenants as of September 30, 2014.

2017 Convertible Notes. On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, at our election, based on an initial conversion rate of 23.4449 shares of our common stock per $1,000 principal amount of 2017 Convertible Notes, which corresponds to an initial conversion price of approximately $42.65 per share of our common stock. On September 30, 2014, our closing share price was $31.36. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes. Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock, at our election. Prior to December 1, 2016, the 2017 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the second scheduled trading day immediately preceding the maturity date.

In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the “Purchased Call Options”) with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the “Dealers”). We paid an aggregate amount of approximately $70.8 million to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes, also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.

We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91 per share of our common stock. We received aggregate proceeds of approximately $40.1 million from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.

As of September 30, 2014, the carrying amount of the liability component of the 2017 Convertible Notes was $262.4 million. During the three and nine months ended September 30, 2014, we recognized $3.5 million and $10.4 million, respectively, of interest expense for the amortization of the discount and $0.3 million and $1.0 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine months ended September 30, 2014, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

Note 6 – Asset Retirement Obligations

The change in our asset retirement obligations during the nine months ended September 30, 2014 is set forth below:


	Nine Months Ended September 30, 2014
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	502.5
Liabilities incurred		24.4
Liabilities settled		(46.6	)
Divestment of properties		(136.4	)
Accretion expense		21.8
Revision of estimates		43.9

Asset retirement obligations as of the end of the period, including current portion	$	409.6

Note 7 – Divestitures

On January 16, 2014, we completed the sale of our interests in the Cut Off and Clovelly fields for cash consideration of approximately $44.8 million and the assumption of the associated asset retirement obligations of approximately $9.2 million. On January 31, 2014, we completed the sale of our interest in the Hatch Point field for cash consideration of approximately $9.7 million and the assumption of the associated asset retirement obligations of approximately $1.2 million. On July 31, 2014, we completed the sale of certain of our non-core properties in the GOM conventional shelf for cash consideration of approximately $177.6 million, after giving effect to preliminary purchase price adjustments, and the assumption of the associated asset retirement obligations of approximately $125.1 million. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 9% of our total estimated proved oil and natural gas reserves. These sales were accounted for as adjustments to capitalized costs, with total consideration (cash consideration plus the assumed asset retirement obligations) recorded as an increase to accumulated depreciation, depletion and amortization (“DD&A”). No gain or loss was recognized since the adjustments did not significantly alter the relationship between capitalized costs and proved reserves.

All of the proceeds from the July 31, 2014 sale of our non-core GOM conventional shelf properties 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, and are included in our balance sheet as restricted cash. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provides for deferral of taxable gain on these sales proceeds. We have until January 27, 2015 (the “Exchange Period”) to close on a transaction for like-kind replacement property in order to achieve deferral of our realized tax gain. The Qualified Trust Agreement and Exchange Agreement provide for certain restrictions on the use of these funds during the Exchange Period.

Note 8 – Fair Value Measurements

U.S. Generally Accepted Accounting Principles (“GAAP”) establish a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of September 30, 2014 and December 31, 2013, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy. For a more detailed description of our derivative instruments, see Note 4 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at September 30, 2014:


	Fair Value Measurements at September 30, 2014
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Marketable securities (Other assets)	$	8.4	$	8.4	$	—	$	—
Derivative contracts		23.1		—		23.1		—

Total	$	31.5	$	8.4	$	23.1	$	—


	Fair Value Measurements at September 30, 2014
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Derivative contracts	$	0.2	$	—	$	0.2	$	—

Total	$	0.2	$	—	$	0.2	$	—

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013:


	Fair Value Measurements at December 31, 2013
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Marketable securities (Other assets)	$	8.2	$	8.2	$	—	$	—
Derivative contracts		5.9		—		5.9		—

Total	$	14.1	$	8.2	$	5.9	$	—


	Fair Value Measurements at December 31, 2013
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Derivative contracts	$	8.3	$	—	$	8.3	$	—

Total	$	8.3	$	—	$	8.3	$	—

The fair value of cash and cash equivalents and our variable-rate bank debt approximated book value at September 30, 2014 and December 31, 2013. As of September 30, 2014 and December 31, 2013, the fair value of the liability component of the 2017 Convertible Notes was approximately $266.7 million and $260.4 million, respectively. As of September 30, 2014 and December 31, 2013, the fair value of the 7¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) was approximately $802.1 million and $814.7 million, respectively.

The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 5 – Long-Term Debt) at inception, September 30, 2014 and December 31, 2013. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

Note 9 – Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component for the three and nine months ended September 30, 2014 were as follows (in millions):


	Cash Flow Hedges			Foreign Currency Items			Total
For the Three Months Ended September 30, 2014
Beginning balance, net of tax	($	17.8	)	($	0.4	)	($	18.2	)

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		47.1			—			47.1
Foreign currency translations		—			(1.6	)		(1.6	)
Income tax effect		(16.9	)		—			(16.9	)

Net of tax		30.2			(1.6	)		28.6

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(1.3	)		—			(1.3	)
Income tax effect		0.5			—			0.5

Net of tax		(0.8	)		—			(0.8	)

Other comprehensive income (loss), net of tax		31.0			(1.6	)		29.4

Ending balance, net of tax	$	13.2		($	2.0	)	$	11.2


	Cash Flow Hedges			Foreign Currency Items			Total
For the Nine Months Ended September 30, 2014
Beginning balance, net of tax	($	1.4	)	($	0.7	)	($	2.1	)

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		3.7			—			3.7
Foreign currency translations		—			(1.3	)		(1.3	)
Income tax effect		(1.2	)		—			(1.2	)

Net of tax		2.5			(1.3	)		1.2

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(17.6	)		—			(17.6	)
Derivative expense, net		(1.5	)		—			(1.5	)
Income tax effect		7.0			—			7.0

Net of tax		(12.1	)		—			(12.1	)

Other comprehensive income (loss), net of tax		14.6			(1.3	)		13.3

Ending balance, net of tax	$	13.2		($	2.0	)	$	11.2

Changes in accumulated other comprehensive income (loss) by component for the three and nine months ended September 30, 2013, were as follows (in millions):


	Cash Flow Hedges			Foreign Currency Items			Total
For the Three Months Ended September 30, 2013
Beginning balance, net of tax	$	25.0		($	0.5	)	$	24.5

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(30.8	)		—			(30.8	)
Foreign currency translations		—			0.3			0.3
Income tax effect		11.1			—			11.1

Net of tax		(19.7	)		0.3			(19.4	)

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(2.1	)		—			(2.1	)
Income tax effect		0.8			—			0.8

Net of tax		(1.3	)		—			(1.3	)

Other comprehensive income (loss), net of tax		(18.4	)		0.3			(18.1	)

Ending balance, net of tax	$	6.6		($	0.2	)	$	6.4


	Cash Flow Hedges			Foreign Currency Items			Total
For the Nine Months Ended September 30, 2013
Beginning balance, net of tax	$	28.8		$	—		$	28.8

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(20.9	)		—			(20.9	)
Foreign currency translations		—			(0.2	)		(0.2	)
Income tax effect		7.6			—			7.6

Net of tax		(13.3	)		(0.2	)		(13.5	)

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		13.8			—			13.8
Income tax effect		(4.9	)		—			(4.9	)

Net of tax		8.9			—			8.9

Other comprehensive loss, net of tax		(22.2	)		(0.2	)		(22.4	)

Ending balance, net of tax	$	6.6		($	0.2	)	$	6.4

Note 10 – Investment in Oil and Gas Properties

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 (excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. At September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47.1 million based on twelve month average prices, net of applicable differentials, of $94.94 per barrel of oil, $4.19 per Mcf of natural gas and $41.33 per barrel of natural gas liquids.

In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Included in unevaluated oil and gas property costs at September 30, 2014 and December 31, 2013, were $25.7 million and $10.6 million, respectively, of capital expenditures related to our oil and gas property investments in Canada.

Note 11 – Commitments and Contingencies

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

In August 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15^th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of approximately $18.4 million plus interest, costs and attorney fees. Kimmeridge alleges that (1) Stone was obligated by virtue of a letter of intent to negotiate in good faith and close an acquisition involving approximately 33,000 net mineral acres in the Illinois basin, and (2) Stone failed to pay brokerage costs incurred after December 31, 2012 pursuant to a separate letter of understanding between Stone and Kimmeridge. Stone denies Kimmeridge’s claims, as well as its damage calculations, and is vigorously defending against both claims. We cannot estimate the potential range of loss at this time.

Note 12 – Subsequent Event

In October 2014, we contracted a deep water drilling rig for our multi-year, deep water program in the GOM. The primary term contract is for 30 months and is expected to commence during the second quarter of 2015 at a rate of approximately $350,000 per day, representing a total commitment of approximately $319 million. The contract permits us to exercise options to extend the term up to an additional 12 months. We also have the option to reduce the primary term contract by up to six months, subject to notification no later than March 31, 2015.

Note 13 – Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

Note 14 – Guarantor Financial Statements

Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents unaudited condensed consolidating financial information as of September 30, 2014 and December 31, 2013 and for the three and nine month periods ended September 30, 2014 and 2013 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

SEPTEMBER 30, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	125,740		$	54,440		$	127		$	—		$	180,307
Restricted cash		177,647			—			—			—			177,647
Accounts receivable		153,685			224,491			34			(204,435	)		173,775
Fair value of derivative contracts		—			16,635			—			—			16,635
Current income tax receivable		7,373			—			—			—			7,373
Deferred taxes *		3,445			20,591			—			—			24,036
Inventory		3,426			283			—			—			3,709
Other current assets		1,876			—			8			—			1,884

Total current assets		473,192			316,440			169			(204,435	)		585,366
Oil and gas properties, full cost method:
Proved		1,563,596			7,128,421			—			—			8,692,017
Less: accumulated DD&A		(613,590	)		(5,954,961	)		—			—			(6,568,551	)

Net proved oil and gas properties		950,006			1,173,460			—			—			2,123,466
Unevaluated		299,225			245,754			25,679			—			570,658
Other property and equipment, net		32,118			—			—			—			32,118
Fair value of derivative contracts		—			6,481			—			—			6,481
Other assets, net		21,464			1,906			17,490			—			40,860
Investment in subsidiary		857,909			—			40,605			(898,514	)		—

Total assets	$	2,633,914		$	1,744,041		$	83,943		($	1,102,949	)	$	3,358,949

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		245,870		$	48,661		$	31,389		($	204,435	)	$	121,485
Undistributed oil and gas proceeds		57,410			1,093			—			—			58,503
Accrued interest		22,240			—			—			—			22,240
Fair value of derivative contracts		—			156			—			—			156
Asset retirement obligations		—			73,451			—			—			73,451
Other current liabilities		57,131			499			—			—			57,630

Total current liabilities		382,651			123,860			31,389			(204,435	)		333,465
Long-term debt		1,037,440			—			—			—			1,037,440
Deferred taxes *		(46,057	)		440,903			—			—			394,846
Asset retirement obligations		2,903			333,294			—			—			336,197
Fair value of derivative contracts		—			24			—			—			24
Other long-term liabilities		41,350			—			—			—			41,350

Total liabilities		1,418,287			898,081			31,389			(204,435	)		2,143,322

Commitments and contingencies
Stockholders’ equity:
Common stock		549			—			—			—			549
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,628,942			1,309,562			56,657			(1,366,219	)		1,628,942
Accumulated deficit		(424,193	)		(476,828	)		(31	)		476,859			(424,193	)
Accumulated other comprehensive income (loss)		11,189			13,226			(4,072	)		(9,154	)		11,189

Total stockholders’ equity		1,215,627			845,960			52,554			(898,514	)		1,215,627

Total liabilities and stockholders’ equity	$	2,633,914		$	1,744,041		$	83,943		($	1,102,949	)	$	3,358,949

*	Deferred income taxes have been allocated to the Guarantor Subsidiary where related oil and gas properties reside.

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2013

(In thousands)


	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	246,294		$	84,290		$	640		$	—		$	331,224
Accounts receivable		74,887			97,128			—			(44	)		171,971
Fair value of derivative contracts		—			4,549			—			—			4,549
Current income tax receivable		7,366			—			—			—			7,366
Deferred taxes *		8,659			23,051			—			—			31,710
Inventory		3,440			283			—			—			3,723
Other current assets		1,874			—			—			—			1,874

Total current assets		342,520			209,301			640			(44	)		552,417
Oil and gas properties, full cost method:
Proved		1,309,527			6,494,590			—			—			7,804,117
Less: accumulated DD&A		(459,932	)		(5,448,828	)		—			—			(5,908,760	)

Net proved oil and gas properties		849,595			1,045,762			—			—			1,895,357
Unevaluated		325,113			388,643			10,583			—			724,339
Other property and equipment, net		26,178			—			—			—			26,178
Fair value of derivative contracts		—			1,378			—			—			1,378
Other assets, net		45,410			1,349			2,128			—			48,887
Investment in subsidiary		747,472			—			12,711			(760,183	)		—

Total assets	$	2,336,288		$	1,646,433		$	26,062		($	760,227	)	$	3,248,556

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	173,147		$	22,530		$	44		($	44	)	$	195,677
Undistributed oil and gas proceeds		34,386			2,643			—			—			37,029
Accrued interest		9,022			—			—			—			9,022
Fair value of derivative contracts		—			7,753			—			—			7,753
Asset retirement obligations		—			67,161			—			—			67,161
Other current liabilities		53,682			838			—			—			54,520

Total current liabilities		270,237			100,925			44			(44	)		371,162
Long-term debt		1,027,084			—			—			—			1,027,084
Deferred taxes *		10,227			380,466			—			—			390,693
Asset retirement obligations		4,945			430,407			—			—			435,352
Fair value of derivative contracts		—			470			—			—			470
Other long-term liabilities		53,509			—			—			—			53,509

Total liabilities		1,366,002			912,268			44			(44	)		2,278,270

Commitments and contingencies
Stockholders’ equity:
Common stock		488			—			—			—			488
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,397,885			1,309,563			27,403			(1,336,966	)		1,397,885
Accumulated deficit		(425,165	)		(574,003	)		(52	)		574,055			(425,165	)
Accumulated other comprehensive loss		(2,062	)		(1,395	)		(1,333	)		2,728			(2,062	)

Total stockholders’ equity		970,286			734,165			26,018			(760,183	)		970,286

Total liabilities and stockholders’ equity	$	2,336,288		$	1,646,433		$	26,062		($	760,227	)	$	3,248,556

*	Deferred income taxes have been allocated to the Guarantor Subsidiary where related oil and gas properties reside.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	11,692		$	112,103		$	—		$	—		$	123,795
Gas production		16,001			14,153			—			—			30,154
Natural gas liquids production		15,820			5,194			—			—			21,014
Other operational income		2,417			51			—			—			2,468
Derivative income, net		—			5,782			—			—			5,782

Total operating revenue		45,930			137,283			—			—			183,213

Operating expenses:
Lease operating expenses		5,619			37,942			—			—			43,561
Transportation, processing and gathering expenses		14,379			2,342			—			—			16,721
Production taxes		2,936			715			—			—			3,651
Depreciation, depletion, amortization		36,598			43,693			—			—			80,291
Write-down of oil and gas properties		47,130			—			—			—			47,130
Accretion expense		56			6,483			—			—			6,539
Salaries, general and administrative		16,273			1			12			—			16,286
Incentive compensation expense		3,092			—			—			—			3,092
Other operational expense		294			4			—			—			298

Total operating expenses		126,377			91,180			12			—			217,569

Income (loss) from operations		(80,447	)		46,103			(12	)		—			(34,356	)

Other (income) expenses:
Interest expense		10,316			7			—			—			10,323
Interest income		(76	)		(82	)		(11	)		—			(169	)
Other income		(164	)		(531	)		—			—			(695	)
Other expense		95			—			—			—			95
(Income) loss from investment in subsidiaries		(29,894	)		—			2			29,892			—

Total other (income) expenses		(19,723	)		(606	)		(9	)		29,892			9,554

Income (loss) before taxes		(60,724	)		46,709			(3	)		(29,892	)		(43,910	)

Provision (benefit) for income taxes:
Current		—			—			—			—			—
Deferred		(31,309	)		16,814			—			—			(14,495	)

Total income taxes		(31,309	)		16,814			—			—			(14,495	)

Net income (loss)	($	29,415	)	$	29,895		($	3	)	($	29,892	)	($	29,415	)

Comprehensive income (loss)	($	65	)	$	29,895		($	3	)	($	29,892	)	($	65	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2013

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	6,904		$	179,704		$	—		$	—		$	186,608
Gas production		19,971			32,757			—			—			52,728
Natural gas liquids production		9,224			7,252			—			—			16,476
Other operational income		711			162			—			—			873

Total operating revenue		36,810			219,875			—			—			256,685

Operating expenses:
Lease operating expenses		3,895			50,091			—			—			53,986
Transportation, processing and gathering expenses		10,072			3,009			—			—			13,081
Production taxes		1,773			3,451			—			—			5,224
Depreciation, depletion, amortization		26,728			66,125			—			—			92,853
Accretion expense		93			8,338			—			—			8,431
Salaries, general and administrative		14,202			—			(1	)		—			14,201
Incentive compensation expense		4,566			—			—			—			4,566
Other operational expenses		194			43			—			—			237
Derivative expense, net		—			1,684			—			—			1,684

Total operating expenses		61,523			132,741			(1	)		—			194,263

Income (loss) from operations		(24,713	)		87,134			1			—			62,422

Other (income) expenses:
Interest expense		7,922			—			—			—			7,922
Interest income		(1,234	)		(69	)		(8	)		—			(1,311	)
Other income		(230	)		(552	)		—			—			(782	)
Income from investment in subsidiaries		(56,166	)		—			(7	)		56,173			—

Total other (income) expenses		(49,708	)		(621	)		(15	)		56,173			5,829

Income before taxes		24,995			87,755			16			(56,173	)		56,593

Provision (benefit) for income taxes:
Current		(88	)		—			—			—			(88	)
Deferred		(11,019	)		31,598			—			—			20,579

Total income taxes		(11,107	)		31,598			—			—			20,491

Net income	$	36,102		$	56,157		$	16		($	56,173	)	$	36,102

Comprehensive income	$	17,985		$	56,157		$	16		($	56,173	)	$	17,985

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	24,182		$	380,295		$	—		$	—		$	404,477
Gas production		65,640			67,543			—			—			133,183
Natural gas liquids production		44,293			20,627			—			—			64,920
Other operational income		5,121			394			—			—			5,515
Derivative income, net		—			2,667			—			—			2,667

Total operating revenue		139,236			471,526			—			—			610,762

Operating expenses:
Lease operating expenses		14,678			125,240			—			—			139,918
Transportation, processing and gathering expenses		35,152			10,293			—			—			45,445
Production taxes		6,520			3,450			—			—			9,970
Depreciation, depletion, amortization		95,038			160,734			—			—			255,772
Write-down of oil and gas properties		47,130			—			—			—			47,130
Accretion expense		185			21,642			—			—			21,827
Salaries, general and administrative		49,237			3			12			—			49,252
Incentive compensation expense		10,129			—			—			—			10,129
Other operational expenses		470			40			—			—			510

Total operating expenses		258,539			321,402			12			—			579,953

Income (loss) from operations		(119,303	)		150,124			(12	)		—			30,809

Other (income) expenses:
Interest expense		28,549			44			—			—			28,593
Interest income		(301	)		(181	)		(23	)		—			(505	)
Other income		(537	)		(1,587	)		—			—			(2,124	)
Other expense		274			—			—			—			274
Income from investment in subsidiaries		(97,186	)		—			(10	)		97,196			—

Total other (income) expenses		(69,201	)		(1,724	)		(33	)		97,196			26,238

Income (loss) before taxes		(50,102	)		151,848			21			(97,196	)		4,571

Provision (benefit) for income taxes:
Current		—			—			—			—			—
Deferred		(51,074	)		54,673			—			—			3,599

Total income taxes		(51,074	)		54,673			—			—			3,599

Net income	$	972		$	97,175		$	21		($	97,196	)	$	972

Comprehensive income	$	14,223		$	97,175		$	21		($	97,196	)	$	14,223

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	20,625		$	537,406		$	—		$	—		$	558,031
Gas production		47,240			90,142			—			—			137,382
Natural gas liquids production		17,901			18,953			—			—			36,854
Other operational income		2,150			509			—			—			2,659

Total operating revenue		87,916			647,010			—			—			734,926

Operating expenses:
Lease operating expenses		9,611			147,936			—			—			157,547
Transportation, processing and gathering expenses		17,853			9,521			—			—			27,374
Production taxes		3,960			7,444			—			—			11,404
Depreciation, depletion, amortization		62,007			193,490			—			—			255,497
Accretion expense		279			24,733			—			—			25,012
Salaries, general and administrative		43,300			4			47			—			43,351
Incentive compensation expense		8,047			—			—			—			8,047
Other operational expense		295			87			—			—			382
Derivative expense, net		—			1,537			—						1,537

Total operating expenses		145,352			384,752			47			—			530,151

Income (loss) from operations		(57,436	)		262,258			(47	)		—			204,775

Other (income) expenses:
Interest expense		26,431			21			—			—			26,452
Interest income		(1,384	)		(144	)		(15	)		—			(1,543	)
Other income		(671	)		(1,519	)		—			—			(2,190	)
(Income) loss from investment in subsidiaries		(168,887	)		—			32			168,855			—

Total other (income) expenses		(144,511	)		(1,642	)		17			168,855			22,719

Income (loss) before taxes		87,075			263,900			(64	)		(168,855	)		182,056

Provision (benefit) for income taxes:
Current		(10,827	)		—			—			—			(10,827	)
Deferred		(17,980	)		94,981			—			—			77,001

Total income taxes		(28,807	)		94,981			—			—			66,174

Net income (loss)	$	115,882		$	168,919		($	64	)	($	168,855	)	$	115,882

Comprehensive income (loss)	$	93,462		$	168,919		($	64	)	($	168,855	)	$	93,462

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	972		$	97,175		$	21		($	97,196	)	$	972
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		95,038			160,734			—			—			255,772
Write-down of oil and gas properties		47,130			—			—			—			47,130
Accretion expense		185			21,642			—			—			21,827
Deferred income tax (benefit) provision		(51,074	)		54,673			—			—			3,599
Settlement of asset retirement obligations		(84	)		(47,133	)		—			—			(47,217	)
Non-cash stock compensation expense		8,409			—			—			—			8,409
Non-cash derivative income		—			(2,386	)		—			—			(2,386	)
Non-cash interest expense		12,393			—			—			—			12,393
Change in current income taxes		(6	)		—			—			—			(6	)
Non-cash income from investment in subsidiaries		(97,185	)		—			(11	)		97,196			—
Change in intercompany receivables/payables		(119,004	)		90,313			28,691			—			—
(Increase) decrease in accounts receivable		125,593			(127,363	)		(35	)		—			(1,805	)
Increase in other current assets		(2	)		—			(8	)		—			(10	)
Increase (decrease) in accounts payable		900			(4,447	)		—			—			(3,547	)
Increase (decrease) in other current liabilities		39,329			(1,888	)		—			—			37,441
Other		1,414			(1,586	)		—			—			(172	)

Net cash provided by operating activities		64,008			239,734			28,658			—			332,400

Cash flows from investing activities:
Investment in oil and gas properties		(225,831	)		(480,686	)		(20,971	)		—			(727,488	)
Proceeds from sale of oil and gas properties, net of expenses		12,197			211,102			—			—			223,299
Investment in fixed and other assets		(8,790	)		—			—			—			(8,790	)
Change in restricted funds		(177,647	)		—			(8,105	)		—			(185,752	)
Investment in subsidiaries		—			—			(29,253	)		29,253			—

Net cash used in investing activities		(400,071	)		(269,584	)		(58,329	)		29,253			(698,731	)

Cash flows from financing activities:
Net proceeds from issuance of common stock		225,999			—			—			—			225,999
Deferred financing costs		(3,329	)		—			—			—			(3,329	)
Equity proceeds from parent		—			—			29,253			(29,253	)		—
Net payments for share-based compensation		(7,161	)		—			—			—			(7,161	)

Net cash provided by financing activities		215,509			—			29,253			(29,253	)		215,509

Effect of exchange rate changes on cash		—			—			(95	)		—			(95	)

Net change in cash and cash equivalents		(120,554	)		(29,850	)		(513	)		—			(150,917	)
Cash and cash equivalents, beginning of period		246,294			84,290			640			—			331,224

Cash and cash equivalents, end of period	$	125,740		$	54,440		$	127		$	—		$	180,307

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(In thousands)


	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	115,882		$	168,919		($	64	)	($	168,855	)	$	115,882
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		62,007			193,490			—			—			255,497
Accretion expense		279			24,733			—			—			25,012
Deferred income tax provision (benefit)		(17,980	)		94,981			—			—			77,001
Settlement of asset retirement obligations		—			(61,178	)		—			—			(61,178	)
Non-cash stock compensation expense		7,583			—			—			—			7,583
Excess tax benefits		(156	)		—			—			—			(156	)
Non-cash derivative expense		—			1,626			—			—			1,626
Non-cash interest expense		12,384			—			—			—			12,384
Non-cash (income) loss from investment in subsidiaries		(168,887	)		—			32			168,855			—
Change in current income taxes		(704	)		—			—			—			(704	)
Change in intercompany receivables/payables		207,267			(207,311	)		44			—			—
(Increase) decrease in accounts receivable		(24,053	)		1,776			—			—			(22,277	)
Decrease in other current assets		2,187			—			—			—			2,187
Decrease in inventory		158			—			—			—			158
Increase in accounts payable		2,610			5,425			—			—			8,035
Increase in other current liabilities		13,613			6,638			—			—			20,251
Other		499			(2,290	)		—			—			(1,791	)

Net cash provided by operating activities		212,689			226,809			12			—			439,510

Cash flows from investing activities:
Investment in oil and gas properties		(234,776	)		(226,695	)		(10,833	)		—			(472,304	)
Proceeds from sale of oil and gas properties, net of expenses		6,300			—			—			—			6,300
Investment in fixed and other assets		(3,830	)		—			—			—			(3,830	)
Change in restricted funds		—			—			(2,394	)		—			(2,394	)
Investment in subsidiaries		(14,000	)		—			(13,404	)		27,404			—

Net cash used in investing activities		(246,306	)		(226,695	)		(26,631	)		27,404			(472,228	)

Cash flows from financing activities:
Deferred financing costs		(11	)		—			—			—			(11	)
Excess tax benefits		156			—			—			—			156
Equity proceeds from parent		—			—			27,404			(27,404	)		—
Net payments for share-based compensation		(3,733	)		—			—			—			(3,733	)

Net cash (used in) provided by financing activities		(3,588	)		—			27,404			(27,404	)		(3,588	)

Effect of exchange rate on cash		—			—			(145	)		—			(145	)

Net change in cash and cash equivalents		(37,205	)		114			640			—			(36,451	)
Cash and cash equivalents, beginning of period		228,398			51,128			—			—			279,526

Cash and cash equivalents, end of period	$	191,193		$	51,242		$	640		$	—		$	243,075

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

Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this “Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our 2013 Annual Report on Form 10-K and in this Form 10-Q.

Forward-looking statements appear in a number of places in this Form 10-Q and include statements with respect to, among other things:

•

any expected results or benefits associated with our acquisitions;

•

expected results from risked weighted drilling success;

•

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

•

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

•

our outlook on oil and natural gas prices;

•

estimates of our oil and natural gas reserves;

•

any estimates of future earnings growth;

•

the impact of political and regulatory developments;

•

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

•

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

•

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

•

the amount, nature and timing of any potential divestiture transactions;

•

our access to capital and our anticipated liquidity;

•

estimates of future income taxes; and

•

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

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

•

commodity price volatility;

•

consequences of a catastrophic event like the Deepwater Horizon oil spill;

•

domestic and worldwide economic conditions;

•

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

•

our level of indebtedness;

•

declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our bank credit facility and impairments;

•

our ability to replace and sustain production;

•

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

•

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

•

third-party interruption of sales to market;

•

inflation;

•

lack of availability and cost of goods and services;

•

market conditions relating to potential acquisition and divestiture transactions;

•

regulatory and environmental risks associated with drilling and production activities;

•

drilling and other operating risks;

•

unsuccessful exploration and development drilling activities;

•

hurricanes and other weather conditions;

•

adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, including changes affecting our offshore and Appalachian operations;

•

uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and

•

other risks described in this Form 10-Q.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, Item 1A. Risk Factors, of this Form 10-Q and (2) Part I, Item 1A, of our 2013 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2013 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our 2013 Annual Report on Form 10-K.

Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have expanded our reserve base outside of the conventional shelf of the GOM and into the more prolific reserve basins of the GOM deep water and GOM deep gas as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia.

Critical Accounting Estimates

Our 2013 Annual Report on Form 10-K describes the accounting estimates 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 natural gas reserve volumes and the timing of their production;

•

estimated costs to develop and produce proved oil and natural gas reserves;

•

accruals of exploration costs, development costs, operating costs and production revenue;

•

timing and future costs to abandon our oil and gas properties;

•

effectiveness and estimated fair value of derivative positions;

•

classification of unevaluated property costs;

•

capitalized general and administrative costs and interest;

•

estimates of fair value in business combinations;

•

current and deferred income taxes; and

•

contingencies.

This Form 10-Q should be read together with the discussion contained in our 2013 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 Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2013 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, regarding our known material risk factors.

Known Trends and Uncertainties

Ceiling Test Write-down – During the three months ended September 30, 2014, we recognized a write-down of our U.S. oil and gas properties. Continued declines or suppression of commodity prices and/or widening negative price differentials (particularly in Appalachia) could result in additional write-downs of our U.S. oil and gas properties in future periods.

Non-U.S. Operations – In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Included in unevaluated oil and gas property costs at September 30, 2014 are $25.7 million of capital expenditures related to our oil and gas property investments in Canada. Under full cost accounting, investments in individual countries represent separate cost centers for the computation of DD&A as well as for full cost ceiling test evaluations. Given that this is our sole investment in Canada, it is possible that upon a more complete evaluation of this project that some or all of this investment could be recognized as a charge to expense on our statement of operations.

Hurricanes – Since a large portion of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible increases to and/or acceleration of plugging and abandonment costs.

Deep Water Operations – We are currently operating two significant properties in the deep water of the GOM. Additionally, we engage in deep water drilling operations. Operations in the deep water can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statement of operations as well as going concern issues.

Earnings Per Share – On March 5, 2012, we issued $300 million of 2017 Convertible Notes. These notes are convertible into cash, shares of our common stock or a combination thereof at our election. Current accounting standards require us to use the treasury method for determining dilution in our diluted earnings per share computation since it is management’s intention to settle the principal amount of the notes in cash. However, if due to changes in facts and circumstances beyond our control, such intention were to change, or it becomes probable that we will be unable to settle the principal in cash, we could be required to change our methodology for determining fully diluted earnings per share to the if-converted method. The if-converted method would result in a substantial dilutive effect on diluted earnings per share when compared to the treasury method.

During the second quarter of 2014, our average stock price exceeded the conversion price of $42.65 per share provided in our 2017 Convertible Notes and had a nominal dilutive impact on our diluted earnings per share computation for such quarter and for the nine months ended September 30, 2014. If our average stock price exceeds the conversion price in future periods, it will have a dilutive impact on our diluted earnings per share computation for such periods. Additionally, if our average stock price were to exceed the strike price of the Sold Warrants in future quarters, this would have an additional dilutive impact on our diluted earnings per share computation. Under U.S. GAAP, the mitigating impact of the antidilutive Purchased Call Options cannot be considered in the computation of diluted shares outstanding.

Liquidity and Capital Resources

As of November 3, 2014, we had $480.8 million of availability under our bank credit facility and cash on hand of approximately $307 million, inclusive of $177.6 million of restricted cash. We received $177.6 million of cash proceeds in July 2014 upon completion of the sale of certain of our non-core GOM conventional shelf properties. These proceeds 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. Compliance with the provisions of these agreements may provide for deferral of our realized tax gain on these sales proceeds and further restricts our access to the proceeds until the earlier of January 27, 2015 or the closing on qualified like-kind replacement properties. Although we identified qualified like-kind replacement properties, it is now unlikely that we will close on a transaction.

In September 2014, our Board of Directors approved an increase in our capital expenditure budget for 2014 from $825 million to $895 million. The increase was the result of drilling successes and follow-up development activity, the added Utica test well, an increase in the number of Marcellus wells to be drilled in 2014 and the approval of the deep water Madison project. Our capital expenditure budget excludes material divestitures and acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest. Based on our outlook of commodity prices and our estimated production, we expect our 2014 capital expenditures to exceed our cash flows from operating activities. We intend to finance our 2014 capital expenditures with cash flows from operating activities, cash on hand, unrestricted proceeds received from onshore property divestitures and proceeds from the May 2014 equity offering. Due to the short-term cash restriction described above, we may need to draw upon our bank credit facility during the fourth quarter of 2014 and/or the first quarter of 2015.

Based on our outlook of commodity prices and our estimated production, we expect our 2015 capital expenditures to exceed our cash flows from operating activities. We intend to finance a portion of our 2015 capital expenditures with cash flows from operating activities, cash on hand and our bank credit facility. However, a portion of our capital expenditures in 2015 may need to be financed from other sources.

We are subject to evaluations by the Bureau of Ocean Energy Management for continuation of our current exemption from supplemental bonding on abandonment obligations. It is possible that future agency action resulting in a loss of exemption could have an adverse impact on our liquidity should we be required to post bonds or letters of credit.

Cash Flows and Working Capital. Net cash provided by operating activities totaled $332.4 million during the nine months ended September 30, 2014 compared to $439.5 million in the comparable period in 2013. The decrease was primarily attributable to the divestiture of certain of our non-core GOM onshore and conventional shelf properties as well as scheduled production downtime at our Pompano deep water platform and Main Pass 288 field.

Net cash used in investing activities totaled $698.7 million during the nine months ended September 30, 2014, which primarily represents our investment in oil and gas properties of $727.5 million offset by unrestricted proceeds from the sale of oil and gas properties of $45.7 million. Net cash used in investing activities totaled $472.2 million during the nine months ended September 30, 2013, which primarily represented our investment in oil and gas properties.

Net cash provided by financing activities totaled $215.5 million during the nine months ended September 30, 2014, which primarily represents net proceeds from the sale of common stock of approximately $226.0 million offset by net payments for share-based compensation of approximately $7.2 million and deferred financing costs of approximately $3.3 million associated with our new bank credit facility. Net cash used in financing activities totaled $3.6 million during the nine months ended September 30, 2013, which primarily represented net payments for share-based compensation.

We had working capital at September 30, 2014 of $251.9 million.

Capital Expenditures. During the three months ended September 30, 2014, additions to oil and gas property costs of $188.3 million included $12.0 million of lease and property acquisition costs, $7.9 million of capitalized SG&A expenses (inclusive of incentive compensation) and $10.8 million of capitalized interest. During the nine months ended September 30, 2014, additions to oil and gas property costs of $734.2 million included $43.2 million of lease and property acquisition costs, $24.0 million of capitalized SG&A expenses (inclusive of incentive compensation) and $34.8 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.

Bank Credit Facility. On June 24, 2014, we entered into an amended and restated revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019. Our initial borrowing base under the bank credit facility was set at $500 million and was reaffirmed at $500 million in October 2014. As of September 30, 2014 and November 3, 2014, we had no outstanding borrowings under the bank credit facility and $19.2 million in letters of credit had been issued pursuant to the bank credit facility, leaving $480.8 million of availability under the bank credit facility. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. The bank credit facility is guaranteed by our only material subsidiary, Stone Offshore.

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

Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. Under the financial covenants of our bank credit facility, we must (1) maintain a ratio of Consolidated Funded Debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.75 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for

the preceding four quarterly periods of not less than 2.50 to 1. As of September 30, 2014, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.02 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 13.62 to 1. In addition, our bank credit facility includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of September 30, 2014.

Common Stock Offering. In May 2014, we sold 5,750,000 shares of our common stock in a public offering at a price of $41.00 per share resulting in net proceeds of approximately $226.0 million after deducting the underwriting discount and offering expenses. The net proceeds are being used for general corporate purposes, which includes development of the Amethyst and Cardona prospects, Utica Shale development and the acquisition of additional Appalachian acreage.

Contractual Obligations and Other Commitments

In addition to our significant contractual obligations and commitments summarized in our 2013 Annual Report on Form 10-K, in October 2014, we contracted a deep water drilling rig for our multi-year, deep water program in the GOM. The primary term contract is for 30 months and is expected to commence during the second quarter of 2015 at a rate of approximately $350,000 per day, representing a total commitment of approximately $319 million. The contract permits us to exercise options to extend the term up to an additional 12 months. We also have the option to reduce the primary term contract by up to six months, subject to notification no later than March 31, 2015.

Results of Operations

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


	Three Months Ended September 30,
	2014		2013		Variance			% Change
Production:
Oil (MBbls)		1,329		1,809		(480	)		(27	%)
Natural gas (MMcf)		10,891		13,866		(2,975	)		(21	%)
Natural gas liquids (“NGLs”) (MBbls)		495		425		70			16	%
Oil, natural gas and NGLs (MMcfe)		21,835		27,270		(5,435	)		(20	%)
Revenue data (in thousands): (1)
Oil revenue	$	123,795	$	186,608	($	62,813	)		(34	%)
Natural gas revenue		30,154		52,728		(22,574	)		(43	%)
NGLs revenue		21,014		16,476		4,538			28	%

Total oil, natural gas and NGL revenue	$	174,963	$	255,812	($	80,849	)		(32	%)
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	94.17	$	107.30	($	13.13	)		(12	%)
Natural gas (per Mcf)		2.77		3.41		(0.64	)		(19	%)
NGLs (per Bbl)		42.45		38.77		3.68			9	%
Oil, natural gas and NGLs (per Mcfe)		8.07		9.46		(1.39	)		(15	%)
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	93.15	$	103.16	($	10.01	)		(10	%)
Natural gas (per Mcf)		2.77		3.80		(1.03	)		(27	%)
NGLs (per Bbl)		42.45		38.77		3.68			9	%
Oil, natural gas and NGLs (per Mcfe)		8.01		9.38		(1.37	)		(15	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.00	$	1.98	$	0.02			1	%
SG&A expenses (2)		0.75		0.52		0.23			44	%
DD&A expense on oil and gas properties		3.63		3.37		0.26			8	%

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

(2)	Excludes incentive compensation expense.


	Nine Months Ended September 30,
	2014		2013		Variance			% Change
Production:
Oil (MBbls)		4,228		5,243		(1,015	)		(19	%)
Natural gas (MMcf)		35,895		35,969		(74	)		N/A
NGLs (MBbls)		1,472		1,048		424			40	%
Oil, natural gas and NGLs (MMcfe)		70,095		73,715		(3,620	)		(5	%)
Revenue data (in thousands): (1)
Oil revenue	$	404,477	$	558,031		($153,554	)		(28	%)
Natural gas revenue		133,183		137,382		(4,199	)		(3	%)
NGLs revenue		64,920		36,854		28,066			76	%

Total oil, natural gas and NGL revenue	$	602,580	$	732,267		($129,687	)		(18	%)
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	98.03	$	105.98		($7.95	)		(8	%)
Natural gas (per Mcf)		3.92		3.50		0.42			12	%
NGLs (per Bbl)		44.10		35.17		8.93			25	%
Oil, natural gas and NGLs (per Mcfe)		8.85		9.75		(0.90	)		(9	%)
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	95.67	$	106.43		($10.76	)		(10	%)
Natural gas (per Mcf)		3.71		3.82		(0.11	)		(3	%)
NGLs (per Bbl)		44.10		35.17		8.93			25	%
Oil, natural gas and NGLs (per Mcfe)		8.60		9.93		(1.33	)		(13	%)
Expenses (per Mcfe):
Lease operating expenses	$	2.00	$	2.14		($0.14	)		(7	%)
SG&A expenses (2)		0.70		0.59		0.11			19	%
DD&A expense on oil and gas properties		3.61		3.43		0.18			5	%

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

(2)	Excludes incentive compensation expense.

Net Income. During the three months ended September 30, 2014, we reported a net loss totaling approximately $29.4 million, or $0.54 per share, compared to net income for the three months ended September 30, 2013 of $36.1 million, or $0.72 per share. During the nine months ended September 30, 2014, we reported net income totaling $1.0 million, or $0.02 per share, compared to net income for the nine months ended September 30, 2013 of $115.9 million, or $2.32 per share. All per share amounts are on a diluted basis.

We follow the full cost method of accounting for oil and gas properties. At September 30, 2014, we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $47.1 million ($30.2 million after taxes). The write-down did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.

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

Production. During the three months ended September 30, 2014, total production volumes decreased to 21.8 Bcfe compared to 27.3 Bcfe produced during the comparable 2013 period, representing a 20% decrease. Oil production during the three months ended September 30, 2014 totaled approximately 1,329,000 Bbls compared to 1,809,000 Bbls produced during the comparable 2013 period. Natural gas production totaled 10.9 Bcf during the three months ended September 30, 2014 compared to 13.9 Bcf during the comparable 2013 period. NGL production during the three months ended September 30, 2014 totaled approximately 495,000 Bbls compared to 425,000 Bbls produced during the comparable 2013 period.

During the nine months ended September 30, 2014, total production volumes decreased to 70.1 Bcfe compared to 73.7 Bcfe produced during the comparable 2013 period, representing a 5% decrease. Oil production during the nine months ended September 30, 2014 totaled approximately 4,228,000 Bbls compared to 5,243,000 Bbls produced during the comparable 2013 period. Natural gas production totaled 35.9 Bcf during the nine months ended September 30, 2014 compared to 36.0 Bcf during the comparable 2013 period. NGL production during the nine months ended September 30, 2014 totaled approximately 1,472,000 Bbls compared to 1,048,000 Bbls produced during the comparable 2013 period.

The decrease in oil production during the three and nine months ended September 30, 2014 was primarily attributable to the divestitures of certain of our non-core GOM onshore and conventional shelf properties. Additionally, production during the nine months ended September 30, 2014 was negatively impacted by scheduled production downtime at our Pompano deep water platform, downtime at our Main Pass 288 field, unscheduled third party pipeline downtime at our Mary field in West Virginia and a slight delay in bringing new Appalachian wells on production. During the nine months ended September 30, 2013, production was negatively impacted by third-party pipeline failures in Appalachia.

Prices. Prices realized during the three months ended September 30, 2014 averaged $93.15 per Bbl of oil, $2.77 per Mcf of natural gas and $42.45 per Bbl of NGLs, or 15% lower, on an Mcfe basis, than average realized prices of $103.16 per Bbl of oil, $3.80 per Mcf of natural gas and $38.77 per Bbl of NGLs during the comparable 2013 period. Prices realized during the nine months ended September 30, 2014 averaged $95.67 per Bbl of oil, $3.71 per Mcf of natural gas and $44.10 per Bbl of NGLs, or 13% lower, on an Mcfe basis, than average realized prices of $106.43 per Bbl of oil, $3.82 per Mcf of natural gas and $35.17 per Bbl of NGLs during the comparable 2013 period. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. Our effective hedging transactions had a minimal impact on average realized natural gas prices and decreased our average realized oil price by $1.02 per Bbl during the three months ended September 30, 2014. During the three months ended September 30, 2013, our effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and decreased our average realized oil price by $4.14 per Bbl. During the nine months ended September 30, 2014, our effective hedging transactions decreased our average realized natural gas price by $0.21 per Mcf and decreased our average realized oil price by $2.36 per Bbl. During the nine months ended September 30, 2013, our effective hedging transactions increased our average realized natural gas price by $0.32 per Mcf and increased our average realized oil price by $0.45 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $175.0 million during the three months ended September 30, 2014 compared to $255.8 million during the comparable period of 2013. The decrease was attributable to a 15% decrease in average realized prices in addition to a 20% decrease in production quantities on a gas equivalent basis. For the nine months ended September 30, 2014 and 2013, oil, natural gas and NGL revenue totaled $602.6 million and $732.3 million, respectively. The decrease was attributable to a 13% decrease in average realized prices in addition to a 5% decrease in production quantities on a gas equivalent basis. Total revenue during the three and nine months ended September 30, 2014 was also lower as a result of the divestitures of certain of our non-core GOM onshore and conventional shelf properties. We expect that total revenue for the three months ending December 31, 2014 will be lower than the comparable 2013 period until we reach full production at our deep water Cardona and Cardona South discoveries.

Expenses. Lease operating expenses during the three months ended September 30, 2014 and 2013 totaled $43.6 million and $54.0 million, respectively. For the nine months ended September 30, 2014 and 2013, lease operating expenses totaled $139.9 million and $157.5 million, respectively. On a unit of production basis, lease operating expenses were $2.00 per Mcfe and $1.98 per Mcfe for the three months ended September 30, 2014 and 2013, respectively, and $2.00 per Mcfe and $2.14 per Mcfe for the nine months ended September 30, 2014 and 2013, respectively. The decrease in lease operating expenses during the nine months ended September 30, 2014 was primarily attributable to a decrease in major maintenance projects and the divestitures of certain of our non-core GOM onshore and conventional shelf properties. We expect lease operating expenses to be lower in future quarters as a result of the divestitures.

Transportation, processing and gathering expenses during the three months ended September 30, 2014 and 2013 totaled $16.7 million and $13.1 million, respectively. For the nine months ended September 30, 2014 and 2013, transportation, processing, and gathering expenses totaled $45.4 million and $27.4 million, respectively. The increases were attributable to higher gas and NGL volumes, particularly in Appalachia, where processing and gathering costs are higher.

DD&A expense on oil and gas properties for the three months ended September 30, 2014 totaled $79.2 million compared to $91.9 million during the comparable period of 2013. For the nine months ended September 30, 2014 and 2013, DD&A expense totaled $252.9 million and $252.8 million, respectively. On a unit of production basis, DD&A expense was $3.63 per Mcfe and $3.37 per Mcfe during the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, DD&A expense, on a unit of production basis, was $3.61 per Mcfe and $3.43 per Mcfe, respectively. The increase in DD&A on a per unit basis was primarily attributable to the higher unit cost of reserve additions attributable to our GOM exploration program.

SG&A expenses (exclusive of incentive compensation) for the three months ended September 30, 2014 were $16.3 million compared to $14.2 million for the three months ended September 30, 2013. For the nine months ended September 30, 2014 and 2013, SG&A expenses (exclusive of incentive compensation) totaled $49.3 million and $43.4 million, respectively. The increase was the result of increased legal fees for the nine months ended September 30, 2014, as well as increased staffing and salary adjustments. SG&A expenses for the nine months ended September 30, 2013 included a reimbursement of $1.6 million of legal fees relating to the settlement of litigation in prior periods.

For the three months ended September 30, 2014 and 2013, incentive compensation expense totaled $3.1 million and $4.6 million, respectively. For the nine months ended September 30, 2014 and 2013, incentive compensation expense totaled $10.1 million and $8.0 million, respectively. These amounts relate to the accrual of estimated incentive compensation bonuses calculated based on the projected achievement of certain strategic objectives for each fiscal year.

Interest expense for the three months ended September 30, 2014 totaled $10.3 million, net of $10.8 million of capitalized interest, compared to interest expense of $7.9 million, net of $11.9 million of capitalized interest, during the comparable 2013 period. For the nine months ended September 30, 2014, interest expense totaled $28.6 million, net of $34.8 million of capitalized interest, compared to interest expense of $26.5 million, net of $32.8 million of capitalized interest, during the comparable 2013 period. The increase in interest expense during the nine months ended September 30, 2014 was primarily the result of interest associated with the $475 million of 2022 Notes issued in November 2013. Partially offsetting this increase was a decrease in interest expense as a result of the redemption in November 2013 of our 8⁵⁄₈% Senior Notes due 2017.

For the nine months ended September 30, 2014 and 2013, we recorded an income tax provision of $3.6 million and $66.2 million, respectively. The increase in our effective tax rate between periods from 36% to 79% was a result of the decrease in our income before taxes, as discussed above, which affected the relationship between our permanent tax differences, primarily IRC Section 162(m) limitations on officer compensation, and income before taxes.

Off-Balance Sheet Arrangements

None.

Recent Accounting Developments

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

Defined Terms

Oil, condensate and NGLs are stated in barrels (“Bbls”) or thousand barrels (“MBbls”). Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil, condensate and NGLs 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. 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 for any given year without the consent of our board of directors. We believe that our hedging positions, taking into consideration the board-approved divestiture of our non-core GOM conventional shelf properties, have hedged approximately 51% of our estimated 2014 production from estimated proved reserves, 48% of our estimated 2015 production from estimated proved reserves and 9% of our estimated 2016 production from estimated proved reserves. See Part I, Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 2013 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 total debt outstanding of $1,075 million at September 30, 2014, all of which bears interest at fixed rates. The $1,075 million of fixed-rate debt is comprised of $300 million face value of the 2017 Convertible Notes and $775 million of the 2022 Notes.

Our bank credit facility is subject to an adjustable interest rate. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of this Form 10-Q. We had no outstanding borrowings under our bank credit facility as of September 30, 2014. If we borrow funds under our bank credit facility, we may be subject to increased sensitivity to interest rate movements.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2014 at the reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended September 30, 2014 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

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone and related costs and attorney’s fees. Stone engaged counsel and removed the cases to federal court. The Parishes oppose removal, and these motions are pending. Stone is in the beginning stages of investigating and evaluating the allegations.

In October 2012, we received a notice from the Bureau of Safety and Environmental Enforcement (“BSEE”) that it was initiating an enforcement proceeding with respect to an Incident of Non-Compliance observed at our Vermillion Block 255 Platform H in April 2012. We believe that the conditions observed were not actually violations of applicable rules and accordingly initiated discussions with BSEE to resolve the matter. Notwithstanding these discussions, by “Reviewing Officer’s Final Decision” dated July 9, 2013, BSEE assessed a penalty against Stone of $200,000 based on $25,000 per day for eight days of alleged improper venting of gas at the platform. An administrative appeal before IBLA is pending. We do not believe that this proceeding will have a material adverse effect on our financial condition or results of operations.

In December 2011, a slope failure occurred adjacent to a well pad where we were drilling a well in Wetzel County, West Virginia. The slope failure was near a stream, and an estimated 250 to 300 cubic yards of soil and debris entered the stream. We responded to the incident by removing the discharged material from the stream and stabilizing the area in which the slope failure occurred. In October 2013, we received notice from the West Virginia Department of Environmental Protection that it was proposing to impose a penalty on us for an unauthorized discharge of pollutants into the affected stream. In January 2014, Stone and the West Virginia Department of Environmental Protection, Office of Oil and Gas (“OOG”), agreed to a Consent Order requiring Stone to pay $284,190, with $170,515 due within 30 days of the signed order and the balance of $113,675 to be applied to a Supplemental Environmental Project (“SEP”) which was approved on August 28, 2014. Stone paid the initial $170,515 and is obligated to complete the SEP no later than March 30, 2015.

In August 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15^th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of $18,372,819 plus interest, costs and attorney fees. Kimmeridge alleges that (1) Stone was obligated by virtue of a letter of intent to negotiate in good faith and close an acquisition involving approximately 33,000 net mineral acres in the Illinois basin, and (2) Stone failed to pay brokerage costs incurred after December 31, 2012 pursuant to a separate letter of understanding between Stone and Kimmeridge. Stone denies Kimmeridge’s claims, as well as its damage calculations, and is vigorously defending against both claims.

In November 2012 and March 2013, after inspecting three Stone locations, the U.S. Environmental Protection Agency (“EPA”) issued two compliance orders relating, respectively, to Stone’s Maury pad site and Stone’s Weekley pad site and associated roads in Wetzel County, West Virginia. The EPA compliance orders allege that Stone placed fill material in United States jurisdictional waters without first obtaining the required Clean Water Act Section 404 permits and require that Stone restore the affected areas. The EPA proposed an administrative penalty and Stone submitted restoration plans for the affected areas. On June 2, 2014, Stone accepted the EPA’s offer to settle both compliance orders for $177,500. The Consent Order became final August 12, 2014, and payment was made.

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

Item 1A. Risk Factors

There have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our 2013 Annual Report on Form 10-K.

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

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the three months ended September 30, 2014:


Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
July 1 – July 31, 2014		4,566	$	46.39		—
August 1 – August 31, 2014		—		—		—
September 1 – September 30, 2014		—		—		—

		4,566	$	46.39		—	$	92,928,632

(1)	Amount includes shares of our common stock withheld from employees and nonemployee directors upon the vesting of restricted stock in order to satisfy the required tax withholding obligations.

(2)	There were no repurchases of our common stock under our repurchase program during the three months ended September 30, 2014.

Item 6. Exhibits


3.1		Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 filed August 7, 2012 (File No. 001-12074)).

3.2		Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 filed February 27, 2014 (File No. 001-12074)).

10.1		Purchase and Sale Agreement (as amended) between Stone Energy Offshore, L.L.C. and Stone Energy Corporation, collectively as the seller, and Talos Energy Offshore LLC, as buyer, dated June 27, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed August 1, 2014 (File No. 001-12074)).

*31.1		Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*31.2		Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*#32.1		Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Taxonomy Extension Schema Document

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

*101.LAB		XBRL Taxonomy Extension Label Linkbase Document

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed or furnished 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.

SIGNATURES

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 thereunto duly authorized.


	STONE ENERGY CORPORATION

Date: November 6, 2014	By:	/s/ Kenneth H. Beer
		Kenneth H. Beer
		Executive Vice President and
		Chief Financial Officer
		(On behalf of the Registrant and as
		Principal Financial Officer)

EXHIBIT INDEX


Exhibit Number		Description

3.1		Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 filed August 7, 2012 (File No. 001-12074)).

3.2		Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 filed February 27, 2014 (File No. 001-12074)).

10.1		Purchase and Sale Agreement (as amended) between Stone Energy Offshore, L.L.C. and Stone Energy Corporation, collectively as the seller, and Talos Energy Offshore LLC, as buyer, dated June 27, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed August 1, 2014 (File No. 001-12074)).

*31.1		Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*31.2		Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*#32.1		Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Taxonomy Extension Schema Document

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

*101.LAB		XBRL Taxonomy Extension Label Linkbase Document

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed or furnished 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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