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10-Q 1 d696990d10q.htm 10-Q 10-Q

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 March 31, 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		70508
Lafayette, Louisiana		(Zip Code)
(Address of principal executive offices)

(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 May 5, 2014, there were 50,413,691 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 March 31, 2014 and December 31, 2013		1
	Condensed Consolidated Statement of Income for the Three Months Ended March 31, 2014 and 2013		2
	Condensed Consolidated Statement of Comprehensive Income for the Three Months Ended March 31, 2014 and 2013		3
	Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 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		20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		27
Item 4.	Controls and Procedures		27

PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		28
Item 1A.	Risk Factors		29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		30
Item 6.	Exhibits		31
	Signatures		32
	Exhibit Index		33

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	March 31, 2014			December 31, 2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	202,761		$	331,224
Accounts receivable		190,573			171,971
Fair value of hedging contracts		745			4,549
Current income tax receivable		7,366			7,366
Deferred taxes		36,098			31,710
Inventory		4,651			3,723
Other current assets		1,774			1,874

Total current assets		443,968			552,417
Oil and gas properties, full cost method of accounting:
Proved		7,898,668			7,804,117
Less: accumulated depreciation, depletion and amortization		(6,052,894	)		(5,908,760	)

Net proved oil and gas properties		1,845,774			1,895,357
Unevaluated		906,043			724,339
Other property and equipment, net		26,975			26,178
Fair value of hedging contracts		1,867			1,378
Other assets, net		37,154			48,887

Total assets	$	3,261,781		$	3,248,556


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	165,973		$	195,677
Undistributed oil and gas proceeds		55,676			37,029
Accrued interest		22,247			9,022
Fair value of hedging contracts		15,277			7,753
Asset retirement obligations		87,927			67,161
Other current liabilities		28,467			54,520

Total current liabilities		375,567			371,162
Long-term debt		1,030,466			1,027,084
Deferred taxes		406,477			390,693
Asset retirement obligations		416,171			435,352
Fair value of hedging contracts		376			470
Other long-term liabilities		46,772			53,509

Total liabilities		2,275,829			2,278,270


Commitments and contingencies

Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 49,083,039 and 48,750,533 shares, respectively		491			488
Treasury stock (16,582 shares, at cost)		(860	)		(860	)
Additional paid-in capital		1,394,694			1,397,885
Accumulated deficit		(399,222	)		(425,165	)
Accumulated other comprehensive loss		(9,151	)		(2,062	)

Total stockholders’ equity		985,952			970,286

Total liabilities and stockholders’ equity	$	3,261,781		$	3,248,556

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

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2014			2013
Operating revenue:
Oil production	$	138,289		$	186,925
Gas production		56,362			36,822
Natural gas liquids production		27,970			9,178
Other operational income		1,209			807

Total operating revenue		223,830			233,732


Operating expenses:
Lease operating expenses		46,903			53,044
Transportation, processing and gathering expenses		14,626			5,397
Production taxes		3,062			2,089
Depreciation, depletion and amortization		82,646			75,435
Accretion expense		7,555			8,263
Salaries, general and administrative expenses		16,329			13,952
Incentive compensation expense		3,134			1,431
Other operational expenses		424			72
Derivative expense, net		599			1,221

Total operating expenses		175,278			160,904


Income from operations		48,552			72,828


Other (income) expenses:
Interest expense		8,357			9,635
Interest income		(143	)		(117	)
Other income		(707	)		(726	)

Total other expenses		7,507			8,792


Income before income taxes		41,045			64,036


Provision (benefit) for income taxes:
Current		—			(3,746	)
Deferred		15,102			27,024

Total income taxes		15,102			23,278


Net income	$	25,943		$	40,758


Basic earnings per share	$	0.52		$	0.82
Diluted earnings per share	$	0.52		$	0.82

Average shares outstanding		49,013			48,619
Average shares outstanding assuming dilution		49,062			48,657

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2014			2013
Net income	$	25,943		$	40,758
Other comprehensive loss, net of tax effect:
Derivatives		(6,590	)		(18,341	)
Foreign currency translation		(499	)		—

Comprehensive income	$	18,854		$	22,417

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	25,943		$	40,758
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		82,646			75,435
Accretion expense		7,555			8,263
Deferred income tax provision		15,102			27,024
Settlement of asset retirement obligations		(9,842	)		(14,880	)
Non-cash stock compensation expense		2,247			2,296
Excess tax benefits		—			(104	)
Non-cash derivative expense		448			1,385
Non-cash interest expense		4,070			4,041
Change in current income taxes		—			(9,402	)
(Increase) decrease in accounts receivable		(18,602	)		19,952
Decrease in other current assets		100			40
(Increase) decrease in inventory		(928	)		158
Increase in accounts payable		1,293			2,004
Increase (decrease) in other current liabilities		5,820			(8,942	)
Other		(380	)		(1,262	)

Net cash provided by operating activities		115,472			146,766


Cash flows from investing activities:
Investment in oil and gas properties		(287,175	)		(160,968	)
Proceeds from sale of oil and gas properties, net of expenses		51,954			—
Investment in fixed and other assets		(1,654	)		(599	)
Change in restricted funds		(358	)		—

Net cash used in investing activities		(237,233	)		(161,567	)


Cash flows from financing activities:
Deferred financing costs		(126	)		(11	)
Excess tax benefits		—			104
Net payments for share-based compensation		(6,565	)		(3,465	)

Net cash used in financing activities		(6,691	)		(3,372	)


Effect of exchange rate changes on cash		(11	)		—


Net change in cash and cash equivalents		(128,463	)		(18,173	)
Cash and cash equivalents, beginning of period		331,224			279,526

Cash and cash equivalents, end of period	$	202,761		$	261,353

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 March 31, 2014 and for the three month periods ended March 31, 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 month period ended March 31, 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 March 31,
	2014			2013
Income (numerator):
*Basic:*
Net income	$	25,943		$	40,758
Net income attributable to participating securities		(537	)		(770	)

Net income attributable to common stock — basic	$	25,406		$	39,988


*Diluted:*
Net income	$	25,943		$	40,758
Net income attributable to participating securities		(537	)		(770	)

Net income attributable to common stock — diluted	$	25,406		$	39,988


Weighted average shares (denominator):
Weighted average shares — basic		49,013			48,619
Dilutive effect of stock options		49			38

Weighted average shares — diluted		49,062			48,657


Basic earnings per share	$	0.52		$	0.82

Diluted earnings per share	$	0.52		$	0.82

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 242,000 shares and 347,000 shares during the three months ended March 31, 2014 and 2013, respectively.

During the three months ended March 31, 2014 and 2013, approximately 333,000 shares and 291,000 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.

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 4 — Long-Term Debt) in cash, we have used the treasury method for determining potential 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 all periods presented, the 2017 Convertible Notes were not dilutive for such periods. Additionally, since the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 4 — Long-Term Debt) for all periods presented, such warrants were also not dilutive for such periods.

Note 3 — 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 hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. These hedges are designated as cash flow hedges upon entering into the contracts. We do not enter into hedging transactions for trading purposes. We have no fair value hedges.

The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operating activities. Instruments not qualifying for hedge accounting treatment are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income). All of our derivative instruments at March 31, 2014 and December 31, 2013 were designated as effective cash flow hedges, however, a small portion of our derivative contracts are typically determined to be ineffective. This is because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. Monthly settlements of ineffective hedges are recognized in earnings through derivative expense (income) and cash flows from 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 tables disclose the location and fair value amounts of derivative instruments reported in our balance sheet at March 31, 2014 and December 31, 2013.


Fair Value of Derivative Instruments at March 31, 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 hedging contracts	$	0.7	Current liabilities: Fair value of hedging contracts	$	15.3
	Long-term assets: Fair value of hedging contracts		1.9	Long-term liabilities: Fair value of hedging contracts		0.4

		$	2.6		$	15.7


Fair Value of Derivative 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 hedging contracts	$	4.5	Current liabilities: Fair value of hedging contracts	$	7.8
	Long-term assets: Fair value of hedging contracts		1.4	Long-term liabilities: Fair value of hedging contracts		0.5

		$	5.9		$	8.3

The following table discloses the before tax effect of derivative instruments on the statement of income for the three month periods ended March 31, 2014 and 2013.


Effect of Derivative Instruments on the Statement of Income for the Three Months Ended March 31, 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	($	17.4	)	($	20.1	)	Operating revenue — oil/gas production	($	7.1	)	$	8.5	Derivative expense, net	($	0.6	)	($	1.2	)

Total	($	17.4	)	($	20.1	)		($	7.1	)	$	8.5		($	0.6	)	($	1.2	)

(a)

For the three months ended March 31, 2014, effective hedging contracts decreased oil revenue by $2.5 million and decreased gas revenue by $4.6 million. For the three months ended March 31, 2013, effective hedging contracts increased oil revenue by $4.5 million and increased gas revenue by $4.0 million.

At March 31, 2014, we had an accumulated other comprehensive loss of $8.0 million, net of tax, related to the fair value of our swap contracts that were outstanding as of March 31, 2014. We believe that approximately $8.9 million, net of tax, of accumulated other comprehensive loss will be reclassified into earnings in the next 12 months.

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 March 31, 2014:


	As Presented Without Netting			Effects of Netting			With Effects of Netting
	(In millions)
Current assets: Fair value of hedging contracts	$	0.7		($	0.7	)	$	—
Long-term assets: Fair value of hedging contracts		1.9			(0.5	)		1.4
Current liabilities: Fair value of hedging contracts		(15.3	)		0.8			(14.5	)
Long-term liabilities: Fair value of hedging contracts		(0.4	)		0.4			—

The following table illustrates our hedging positions for calendar years 2014, 2015 and 2016 as of May 5, 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
2015		10,000			4.255

2016		10,000			4.110
2016		10,000			4.120

(a)	October through December

(b)	February through December

(c)	January through June

(d)	Brent crude oil contract

Note 4 — Long-Term Debt

Long-term debt consisted of the following at:


	March 31, 2014		December 31, 2013
	(In millions)
1³⁄₄% Senior Convertible Notes due 2017	$	255.5	$	252.1
7¹⁄₂% Senior Notes due 2022		775.0		775.0
Bank debt		—		—

Total long-term debt	$	1,030.5	$	1,027.1

Bank Debt

On April 26, 2011, we entered into an amended and restated revolving credit facility with commitments totaling $700 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. Our borrowing base is currently set at $400 million. As of March 31 and May 5, 2014, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.4 million had been issued pursuant to our bank credit facility, leaving $378.6 million of availability under our bank credit facility.

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders, taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our bank credit facility is guaranteed by our only significant subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”). Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and natural gas reserves reviewed in determining the borrowing base. At Stone’s option, loans under our bank credit facility will bear interest at a rate based on the adjusted London Interbank Offering (“Libor”) Rate plus an applicable margin, or a rate based on the prime rate or federal funds rate plus an applicable margin. Our bank credit facility provides for optional and mandatory prepayments, affirmative and negative covenants and interest coverage ratio and leverage ratio maintenance covenants. We were in compliance with all covenants as of March 31, 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 March 31, 2014, our closing share price was $41.97. 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(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 March 31, 2014, the carrying amount of the liability component of the 2017 Convertible Notes was $255.5 million. During the three months ended March 31, 2014, we recognized $3.4 million of interest expense for the amortization of the discount and $0.3 million of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three months ended March 31, 2014, we recognized $1.3 million of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

Note 5 — Asset Retirement Obligations

The change in our asset retirement obligations during the three months ended March 31, 2014 is set forth below:


	Three Months Ended March 31, 2014
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	502.5
Liabilities incurred		14.2
Liabilities settled		(9.8	)
Divestment of properties		(10.4	)
Accretion expense		7.6

Asset retirement obligations as of the end of the period, including current portion	$	504.1

Note 6 — 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. These sales were accounted for as an adjustment to capitalized costs with no gain or loss recognized.

Note 7 — Fair Value Measurements

U.S. Generally Accepted Accounting Principles 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 March 31, 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 3 — 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 March 31, 2014:


	Fair Value Measurements at March 31, 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	$	8.5	$	8.5	$	—	$	—
Hedging contracts		2.6		—		2.6		—

Total	$	11.1	$	8.5	$	2.6	$	—


	Fair Value Measurements at March 31, 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)
Hedging contracts	$	15.7	$	—	$	15.7	$	—

Total	$	15.7	$	—	$	15.7	$	—

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	$	8.2	$	8.2	$	—	$	—
Hedging 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)
Hedging 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 March 31, 2014 and December 31, 2013. As of March 31, 2014 and December 31, 2013, the fair value of the liability component of the 2017 Convertible Notes was approximately $267.7 million and $260.4 million, respectively. As of March 31, 2014 and December 31, 2013, the fair value of the 7¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) was approximately $840.9 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 4 — Long-Term Debt) at inception, March 31, 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 8 — Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component for the three months ended March 31, 2014 were as follows (in millions):


For the Three Months Ended March 31, 2014	Cash Flow Hedges			Foreign Currency Items			Total
Beginning balance, net of tax	($	1.4	)	($	0.7	)	($	2.1	)


Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(17.4	)		—			(17.4	)
Foreign currency translations		—			(0.5	)		(0.5	)
Income tax effect		6.3			—			6.3

Net of tax		(11.1	)		(0.5	)		(11.6	)


Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		(7.1	)		—			(7.1	)
Income tax effect		2.6			—			2.6

Net of tax		(4.5	)		—			(4.5	)


Other comprehensive loss, net of tax		(6.6	)		(0.5	)		(7.1	)

Ending balance, net of tax	($	8.0	)	($	1.2	)	($	9.2	)

For the three months ended March 31, 2013, the only component of accumulated other comprehensive income (loss) related to our cash flow hedges. Changes in accumulated other comprehensive income (loss) for the three months ended March 31, 2013 were as follows (in millions):


For the Three Months Ended March 31, 2013	Cash Flow Hedges
Beginning balance, net of tax	$	28.8


Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(20.1	)
Income tax effect		7.3

Net of tax		(12.8	)


Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		8.5
Income tax effect		(3.0	)

Net of tax		5.5


Other comprehensive loss, net of tax		(18.3	)

Ending balance, net of tax	$	10.5

Note 9 — Investment in Oil and Gas Properties

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 March 31, 2014 and December 31, 2013, were $11.3 million and $10.6 million, respectively, of capital expenditures related to our oil and gas property investments in Canada.

Note 10 — Commitments and Contingencies

We are named as a defendant in certain lawsuits and are a party to certain 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 intends to vigorously defend against both claims. We cannot estimate the potential range of loss at this time.

Note 11 — 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 March 31, 2014 and December 31, 2013 and for the three month periods ended March 31, 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

MARCH 31, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	148,239		$	54,347		$	175		$	—		$	202,761
Accounts receivable		103,049			133,644			—			(46,120	)		190,573
Fair value of hedging contracts		—			745			—			—			745
Current income tax receivable		7,366			—			—			—			7,366
Deferred taxes *		1,493			34,605			—			—			36,098
Inventory		4,368			283			—			—			4,651
Other current assets		1,774			—			—			—			1,774

Total current assets		266,289			223,624			175			(46,120	)		443,968
Oil and gas properties, full cost method:
Proved		1,370,697			6,527,971			—			—			7,898,668
Less: accumulated DD&A		(498,058	)		(5,554,836	)		—			—			(6,052,894	)

Net proved oil and gas properties		872,639			973,135			—			—			1,845,774
Unevaluated		318,865			575,845			11,333			—			906,043
Other property and equipment, net		26,975			—			—			—			26,975
Fair value of hedging contracts		—			1,867			—			—			1,867
Other assets, net		31,058			1,348			4,748			—			37,154
Investment in subsidiary		777,728			—			16,171			(793,899	)		—

Total assets	$	2,293,554		$	1,775,819		$	32,427		($	840,019	)	$	3,261,781


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	127,122		$	81,527		$	3,444		($	46,120	)	$	165,973
Undistributed oil and gas proceeds		53,140			2,536			—			—			55,676
Accrued interest		22,247			—			—			—			22,247
Fair value of hedging contracts		—			15,277			—			—			15,277
Asset retirement obligations		—			87,927			—			—			87,927
Other current liabilities		26,915			1,552			—			—			28,467

Total current liabilities		229,424			188,819			3,444			(46,120	)		375,567
Long-term debt		1,030,466			—			—			—			1,030,466
Deferred taxes *		(2,845	)		409,322			—			—			406,477
Asset retirement obligations		3,785			412,386			—			—			416,171
Fair value of hedging contracts		—			376			—			—			376
Other long-term liabilities		46,772			—			—			—			46,772

Total liabilities		1,307,602			1,010,903			3,444			(46,120	)		2,275,829

Commitments and contingencies
Stockholders’ equity:
Common stock		491			—			—			—			491
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,394,694			1,309,562			31,359			(1,340,921	)		1,394,694
Accumulated deficit		(399,222	)		(536,662	)		(44	)		536,706			(399,222	)
Accumulated other comprehensive loss		(9,151	)		(7,984	)		(2,332	)		10,316			(9,151	)

Total stockholders’ equity		985,952			764,916			28,983			(793,899	)		985,952

Total liabilities and stockholders’ equity	$	2,293,554		$	1,775,819		$	32,427		($	840,019	)	$	3,261,781

*	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 hedging 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 hedging 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 hedging 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 hedging 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 INCOME

THREE MONTHS ENDED MARCH 31, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	6,636		$	131,653		$	—		$	—		$	138,289
Gas production		28,839			27,523			—			—			56,362
Natural gas liquids production		18,254			9,716			—			—			27,970
Other operational income		1,042			167			—			—			1,209

Total operating revenue		54,771			169,059			—			—			223,830


Operating expenses:
Lease operating expenses		4,013			42,890			—			—			46,903
Transportation, processing and gathering expenses		10,317			4,309			—			—			14,626
Production taxes		1,681			1,381			—			—			3,062
Depreciation, depletion, amortization		28,055			54,591			—			—			82,646
Accretion expense		68			7,487			—			—			7,555
Salaries, general and administrative		16,325			2			2			—			16,329
Incentive compensation expense		3,134			—			—			—			3,134
Other operational expenses		394			30			—			—			424
Derivative expense, net		—			599			—			—			599

Total operating expenses		63,987			111,289			2			—			175,278


Income (loss) from operations		(9,216	)		57,770			(2	)		—			48,552


Other (income) expenses:
Interest expense		8,353			4			—			—			8,357
Interest income		(79	)		(58	)		(6	)		—			(143	)
Other income		(181	)		(526	)		—			—			(707	)
Income from investment in subsidiaries		(37,345	)		—			(4	)		37,349			—

Total other (income) expenses		(29,252	)		(580	)		(10	)		37,349			7,507


Income before taxes		20,036			58,350			8			(37,349	)		41,045


Provision (benefit) for income taxes:
Current		—			—			—			—			—
Deferred		(5,907	)		21,009			—			—			15,102

Total income taxes		(5,907	)		21,009			—			—			15,102

Net income	$	25,943		$	37,341		$	8		($	37,349	)	$	25,943


Comprehensive income	$	18,854		$	37,341		$	8		($	37,349	)	$	18,854

CONDENSED CONSOLIDATING STATEMENT OF INCOME

THREE MONTHS ENDED MARCH 31, 2013

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenue:
Oil production	$	5,343		$	181,582		$	—	$	—		$	186,925
Gas production		7,198			29,624			—		—			36,822
Natural gas liquids production		2,299			6,879			—		—			9,178
Other operational income		649			158			—		—			807

Total operating revenue		15,489			218,243			—		—			233,732


Operating expenses:
Lease operating expenses		2,291			50,753			—		—			53,044
Transportation, processing and gathering expenses		2,052			3,345			—		—			5,397
Production taxes		867			1,222			—		—			2,089
Depreciation, depletion, amortization		10,191			65,244			—		—			75,435
Accretion expense		93			8,170			—		—			8,263
Salaries, general and administrative		13,948			4			—		—			13,952
Incentive compensation expense		1,431			—			—		—			1,431
Other operational expenses		50			22			—					72
Derivative expense, net		—			1,221			—		—			1,221

Total operating expenses		30,923			129,981			—		—			160,904


Income (loss) from operations		(15,434	)		88,262			—		—			72,828


Other (income) expenses:
Interest expense		9,627			8			—		—			9,635
Interest income		(80	)		(37	)		—		—			(117	)
Other income		(224	)		(502	)		—		—			(726	)
Income from investment in subsidiaries		(56,828	)		—			—		56,828			—

Total other (income) expenses		(47,505	)		(531	)		—		56,828			8,792


Income before taxes		32,071			88,793			—		(56,828	)		64,036


Provision (benefit) for income taxes:
Current		(3,746	)		—			—		—			(3,746	)
Deferred		(4,941	)		31,965			—		—			27,024

Total income taxes		(8,687	)		31,965			—		—			23,278

Net income	$	40,758		$	56,828		$	—	($	56,828	)	$	40,758


Comprehensive income	$	22,417		$	56,828		$	—	($	56,828	)	$	22,417

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	25,943		$	37,341		$	8		($	37,349	)	$	25,943
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		28,055			54,591			—			—			82,646
Accretion expense		68			7,487			—			—			7,555
Deferred income tax provision (benefit)		(5,907	)		21,009			—			—			15,102
Settlement of asset retirement obligations		—			(9,842	)		—			—			(9,842	)
Non-cash stock compensation expense		2,247			—			—			—			2,247
Non-cash derivative expense		—			448			—			—			448
Non-cash interest expense		4,070			—			—			—			4,070
Non-cash income from investment in subsidiaries		(37,345	)		—			(4	)		37,349			—
Change in intercompany receivables/payables		(51,037	)		47,637			3,400			—			—
(Increase) decrease in accounts receivable		(24,762	)		6,160			—			—			(18,602	)
Decrease in other current assets		100			—			—			—			100
Increase in inventory		(928	)		—			—			—			(928	)
Increase (decrease) in accounts payable		1,501			(208	)		—			—			1,293
Increase in other current liabilities		5,212			608			—			—			5,820
Other		145			(525	)		—			—			(380	)

Net cash (used in) provided by operating activities		(52,638	)		164,706			3,404			—			115,472


Cash flows from investing activities:
Investment in oil and gas properties		(46,772	)		(236,903	)		(3,500	)		—			(287,175	)
Proceeds from sale of oil and gas properties, net of expenses		9,700			42,254			—			—			51,954
Investment in fixed and other assets		(1,654	)		—			—			—			(1,654	)
Change in restricted funds		—			—			(358	)		—			(358	)
Investment in subsidiaries		—			—			(3,955	)		3,955			—

Net cash used in investing activities		(38,726	)		(194,649	)		(7,813	)		3,955			(237,233	)


Cash flows from financing activities:
Deferred financing costs		(126	)		—			—			—			(126	)
Equity proceeds from parent		—			—			3,955			(3,955	)		—
Net payments for share-based compensation		(6,565	)		—			—			—			(6,565	)

Net cash (used in) provided by financing activities		(6,691	)		—			3,955			(3,955	)		(6,691	)


Effect of exchange rate changes on cash		—			—			(11	)		—			(11	)


Net change in cash and cash equivalents		(98,055	)		(29,943	)		(465	)		—			(128,463	)
Cash and cash equivalents, beginning of period		246,294			84,290			640			—			331,224

Cash and cash equivalents, end of period	$	148,239		$	54,347		$	175		$	—		$	202,761

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2013

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	40,758		$	56,828		$	—	($	56,828	)	$	40,758
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,191			65,244			—		—			75,435
Accretion expense		93			8,170			—		—			8,263
Deferred income tax provision (benefit)		(4,941	)		31,965			—		—			27,024
Settlement of asset retirement obligations		—			(14,880	)		—		—			(14,880	)
Non-cash stock compensation expense		2,296			—			—		—			2,296
Excess tax benefits		(104	)		—			—		—			(104	)
Non-cash derivative expense		—			1,385			—		—			1,385
Non-cash interest expense		4,041			—			—		—			4,041
Non-cash income from investment in subsidiaries		(56,828	)		—			—		56,828			—
Change in current income taxes		(9,402	)		—			—		—			(9,402	)
Change in intercompany receivables/payables		122,912			(122,912	)		—		—			—
Decrease in accounts receivable		10,668			9,284			—		—			19,952
Decrease in other current assets		40			—			—		—			40
Decrease in inventory		158			—			—		—			158
Increase (decrease) in accounts payable		(1,890	)		3,894			—		—			2,004
Increase (decrease) in other current liabilities		(20,011	)		11,069			—		—			(8,942	)
Other		(761	)		(501	)		—		—			(1,262	)

Net cash provided by operating activities		97,220			49,546			—		—			146,766


Cash flows from investing activities:
Investment in oil and gas properties		(111,458	)		(49,510	)		—		—			(160,968	)
Investment in fixed and other assets		(599	)		—			—		—			(599	)

Net cash used in investing activities		(112,057	)		(49,510	)		—		—			(161,567	)


Cash flows from financing activities:
Deferred financing costs		(11	)		—			—		—			(11	)
Excess tax benefits		104			—			—		—			104
Net payments for share-based compensation		(3,465	)		—			—		—			(3,465	)

Net cash used in financing activities		(3,372	)		—			—		—			(3,372	)


Net change in cash and cash equivalents		(18,209	)		36			—		—			(18,173	)
Cash and cash equivalents, beginning of period		228,398			51,128			—		—			279,526

Cash and cash equivalents, end of period	$	210,189		$	51,164		$	—	$	—		$	261,353

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 gas production;

•

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

•

our outlook on oil and gas prices;

•

estimates of our oil and 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 Gulf of Mexico (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

Hurricanes — Since the majority 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 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 are engaged 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 income as well as going concern issues.

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 March 31, 2014 are $11.3 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 depreciation, depletion and amortization (“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 income.

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 potential 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.

In addition, in the second quarter of 2014 to date, our average stock price has exceeded the conversion price of $42.65 per share provided in our 2017 Convertible Notes. If this condition were to be maintained, it will have a dilutive impact on our diluted earnings per share computation in future quarters. Additionally, if our average stock price were to exceed the strike price of the Sold Warrants in future quarters, this would also have a dilutive impact on our diluted earnings per share computation. Under U.S. Generally Accepted Accounting Principles, the mitigating impact of the antidilutive Purchased Call Options cannot be considered in the computation of diluted shares outstanding.

Sale of Shelf Properties — In 2013, we engaged a financial advisor to market certain of our properties in the GOM conventional shelf, state waters and onshore Louisiana, and to date have completed the sales of our interests in the Weeks Island, Cut Off and Clovelly fields. Sales of oil and gas properties under the full cost method are accounted for as an adjustment to capitalized costs unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the applicable cost center. If such relationship would be altered significantly, we would be required to allocate the cost center between the properties sold and the properties retained and to recognize a gain or loss on the sale in the period in which the transaction is consummated. The Weeks Island, Cut Off and Clovelly sales did not result in a significant alteration of this relationship and, consequently, no gain or loss was recognized. Whether a significant alteration would occur on future transactions, and therefore a gain or loss recognized, cannot be determined at this time.

Liquidity and Capital Resources

As of May 5, 2014, we had $378.6 million of availability under our bank credit facility and cash on hand of approximately $155 million. Our capital expenditure budget for 2014 has been set at $825 million, which excludes material acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest. In addition, pending the results of our drilling program in the first half of 2014, we may have additional capital requirements in 2014 related to the development of our oil and gas properties, which would require an increase in our capital expenditure budget for 2014. Any increase in our capital expenditure budget will be subject to approval of our Board of Directors. 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 a portion of our capital expenditure budget with cash flows from operating activities, cash on hand and our bank credit facility. However, a portion of our capital expenditure budget will likely need to be financed from other sources. We are considering accessing the public or private markets or monetizing other assets as a source of financing.

Cash Flows and Working Capital. Net cash provided by operating activities totaled $115.5 million during the three months ended March 31, 2014 compared to $146.8 million in the comparable period in 2013.

Net cash used in investing activities totaled $237.2 million during the three months ended March 31, 2014, which primarily represents our investment in oil and natural gas properties of $287.2 million offset by proceeds from the sale of oil and natural gas properties of $52.0 million. Net cash used in investing activities totaled $161.6 million during the three months ended March 31, 2013, which primarily represents our investment in oil and natural gas properties.

Net cash used in financing activities totaled $6.7 million and $3.4 million during the three months ended March 31, 2014 and 2013, respectively, which primarily represents net payments for share-based compensation.

We had working capital at March 31, 2014 of $68.4 million.

Capital Expenditures. During the three months ended March 31, 2014, additions to oil and gas property costs of $276.3 million included $2.1 million of lease and property acquisition costs, $7.7 million of capitalized SG&A expenses (inclusive of incentive compensation) and $12.8 million of capitalized interest. These investments were financed with cash on hand and cash flows from operations.

Bank Credit Facility. On April 26, 2011, we entered into an amended and restated revolving credit facility with commitments totaling $700 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. Our borrowing base is currently set at $400 million. As of March 31 and May 5, 2014, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.4 million had been issued pursuant to our bank credit facility, leaving $378.6 million of availability under our bank credit facility.

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

Under the financial covenants of our bank credit facility, we must (1) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (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 3.0 to 1. As of March 31, 2014, our debt to EBITDA ratio was 1.78 to 1 and our EBITDA to consolidated Net Interest Expense ratio was approximately 18.59 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 ownership 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 March 31, 2014.

Results of Operations

The following table sets forth certain information with respect to our oil and gas operations.


	Three Months Ended March 31,
	2014		2013		Variance			% Change
Production:
Oil (MBbls)		1,418		1,667		(249	)		(15	%)
Natural gas (MMcf)		12,641		10,358		2,283			22	%
Natural gas liquids (“NGLs”) (MBbls)		510		216		294			136	%
Oil, natural gas and NGLs (MMcfe)		24,209		21,656		2,553			12	%
Revenue data (in thousands):(1)
Oil revenue	$	138,289	$	186,925	($	48,636	)		(26	%)
Natural gas revenue		56,362		36,822		19,540			53	%
NGLs revenue		27,970		9,178		18,792			205	%

Total oil, natural gas and NGL revenue	$	222,621	$	232,925	($	10,304	)		(4	%)
Average prices:(1)
Oil (per Bbl)	$	97.52	$	112.13	($	14.61	)		(13	%)
Natural gas (per Mcf)		4.46		3.55		0.91			26	%
NGLs (per Bbl)		54.84		42.49		12.35			29	%
Oil, natural gas and NGLs (per Mcfe)		9.20		10.76		(1.56	)		(15	%)
Expenses (per Mcfe):
Lease operating expenses	$	1.94	$	2.45	($	0.51	)		(21	%)
SG&A expenses(2)		0.67		0.64		0.03			5	%
DD&A expense on oil and gas properties		3.38		3.44		(0.06	)		(2	%)

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

(2)	Excludes incentive compensation expense.

Net Income. During the three months ended March 31, 2014, we reported net income totaling $25.9 million, or $0.52 per share, compared to net income for the three months ended March 31, 2013 of $40.8 million, or $0.82 per share. All per share amounts are on a diluted basis.

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

Production. During the three months ended March 31, 2014, total production volumes increased to 24.2 Bcfe compared to 21.7 Bcfe produced during the comparable 2013 period, representing a 12% increase. Oil production during the three months ended March 31, 2014 totaled approximately 1,418,000 Bbls compared to 1,667,000 Bbls produced during the comparable 2013 period. Natural gas production totaled 12.6 Bcf during the three months ended March 31, 2014 compared to 10.4 Bcf during the comparable 2013 period. NGL production during the three months ended March 31, 2014 totaled approximately 510,000 Bbls compared to 216,000 Bbls produced during the comparable 2013 period.

The increase in gas production during the three months ended March 31, 2014 was attributable to new wells in the Mary and Heather fields that were brought online during the fourth quarter of 2013 and the third well in the La Cantera field that was brought online during the second quarter of 2013. The decrease in oil production during the three months ended March 31, 2014 was attributable to extended downtime at our Main Pass 288 field. During the three months ended March 31, 2014, production was negatively impacted by weather-related logistical issues in Appalachia. During the three months ended March 31, 2013, production was negatively impacted by third-party pipeline failures in Appalachia.

Prices. Prices realized during the three months ended March 31, 2014 averaged $97.52 per Bbl of oil, $4.46 per Mcf of natural gas and $54.84 per Bbl of NGLs, or 15% lower, on an Mcfe basis, than average realized prices of $112.13 per Bbl of oil, $3.55 per Mcf of natural gas and $42.49 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 hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. Our effective hedging transactions decreased our average realized natural gas price by $0.36 per Mcf and decreased our average realized oil price by $1.75 per Bbl during the three months ended March 31, 2014. During the three months ended March 31, 2013, our effective hedging transactions increased our average realized natural gas price by $0.38 per Mcf and increased our average realized oil price by $2.72 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $222.6 million during the three months ended March 31, 2014 compared to $232.9 million during the comparable period of 2013. The decrease was attributable to a 15% decrease in average realized prices, which was partially offset by a 12% increase in production quantities on a gas equivalent basis.

Expenses. Lease operating expenses during the three months ended March 31, 2014 and 2013 totaled $46.9 million and $53.0 million, respectively. On a unit of production basis, lease operating expenses were $1.94 per Mcfe and $2.45 per Mcfe for the three months ended March 31, 2014 and 2013, respectively. The decrease in lease operating expenses during the three months ended March 31, 2014 was primarily attributable to a decrease in insurance and major maintenance projects.

Transportation, processing and gathering expenses during the three months ended March 31, 2014 and 2013 totaled $14.6 million and $5.4 million, respectively. The increase was 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 March 31, 2014 totaled $81.8 million compared to $74.5 million during the comparable period of 2013. The increase was primarily due to increased production volumes during the three months ended March 31, 2014. On a unit of production basis, DD&A expense was $3.38 per Mcfe and $3.44 per Mcfe during the three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014, we had in excess of $351 million of unevaluated costs that will likely become evaluated during 2014. We anticipate that the inclusion of these costs in our depletable base will likely increase our DD&A rate in future quarters.

SG&A expenses (exclusive of incentive compensation) for the three months ended March 31, 2014 were $16.3 million compared to $14.0 million for the three months ended March 31, 2013. The increase was primarily the result of increased legal fees for the three months ended March 31, 2014. SG&A expenses for the three months ended March 31, 2013 include a reimbursement of $1.6 million of legal fees relating to the settlement of litigation in prior periods.

For the three months ended March 31, 2014 and 2013, incentive compensation expense totaled $3.1 million and $1.4 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 March 31, 2014 totaled $8.4 million, net of $12.8 million of capitalized interest, compared to interest expense of $9.6 million, net of $10.0 million of capitalized interest, during the comparable 2013 period. The decrease in interest expense was primarily the result of an increase in the amount of interest capitalized to oil and gas properties.

Off-Balance Sheet Arrangements

None.

Recent Accounting Developments

None.

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 current hedging positions have hedged approximately 49% of our estimated 2014 production from estimated proved reserves, 35% of our estimated 2015 production from estimated proved reserves and 8% of our estimated 2016 production from estimated proved reserves. See Part I, Item 1. Financial Statements — Note 3 — 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 March 31, 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 March 31, 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 March 31, 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 March 31, 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. We are pursuing an administrative appeal of this decision. 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. On January 9, 2014, Stone and the West Virginia Department of Environmental Protection, Office of Oil and Gas, 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 within one year of entry of the Consent Order. On March 31, 2014, Stone received the signed order.

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 intends to vigorously defend 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 further, require that Stone restore the affected areas. The EPA proposes to impose an administrative penalty for failure to obtain prior authorization for the well pad and road construction activities. Stone submitted restoration plans for the affected areas and we are negotiating the amount of the proposed penalty with the EPA. We do not expect the costs of restoration or the amount of the penalty to be material to our operations.

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 March 31, 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
January 1 — January 31, 2014		200,814	$	32.69		—
February 1 — February 28, 2014		19		33.63		—
March 1 — March 31, 2014		—		—		—

		200,833	$	32.69		—	$	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 March 31, 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)).

*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.

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)).

*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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company