STONE ENERGY CORP - FORM 10-Q

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file	filename
EXCEL - IDEA: XBRL DOCUMENT - STONE ENERGY CORP	Financial_Report.xls
EX-31.1 - EX-31.1 - STONE ENERGY CORP	d901444dex311.htm
EX-32.1 - EX-32.1 - STONE ENERGY CORP	d901444dex321.htm
EX-31.2 - EX-31.2 - STONE ENERGY CORP	d901444dex312.htm

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, 2015

¨	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 May 4, 2015, there were 57,190,456 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, 2015 and December 31, 2014	1

	Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2015 and 2014	2

	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 and 2014	3

	Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2015 and 2014	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25

Item 4.	Controls and Procedures	25

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	27

Item 1A.	Risk Factors	28

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 6.	Exhibits	29

	Signatures	30

	Exhibit Index	31

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	March 31,			December 31,
	2015			2014
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	162,128		$	74,488
Restricted cash		—			177,647
Accounts receivable		112,150			120,359
Fair value of derivative contracts		124,192			139,179
Current income tax receivable		24			7,212
Inventory		3,709			3,709
Other current assets		6,234			8,118

Total current assets		408,437			530,712
Oil and gas properties, full cost method of accounting:
Proved		8,887,832			8,817,268
Less: accumulated depreciation, depletion and amortization		(7,546,222	)		(6,970,631	)

Net proved oil and gas properties		1,341,610			1,846,637
Unevaluated		602,467			567,365
Other property and equipment, net		31,828			32,340
Fair value of derivative contracts		13,966			14,333
Other assets, net		24,672			27,224

Total assets	$	2,422,980		$	3,018,611

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	68,146		$	132,629
Undistributed oil and gas proceeds		26,202			23,232
Accrued interest		22,243			9,022
Deferred taxes		23,378			20,119
Asset retirement obligations		60,837			69,400
Other current liabilities		40,286			49,505

Total current liabilities		241,092			303,907
Long-term debt		1,044,675			1,041,035
Deferred taxes		98,194			286,343
Asset retirement obligations		244,835			247,009
Other long-term liabilities		31,604			38,714

Total liabilities		1,660,400			1,917,008

Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 55,254,713 and 54,884,542 shares, respectively		553			549
Treasury stock (16,582 shares, at cost)		(860	)		(860	)
Additional paid-in capital		1,634,171			1,633,307
Accumulated deficit		(942,096	)		(614,708	)
Accumulated other comprehensive income		70,812			83,315

Total stockholders’ equity		762,580			1,101,603

Total liabilities and stockholders’ equity	$	2,422,980		$	3,018,611

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 March 31,
	2015			2014
Operating revenue:
Oil production	$	107,507		$	138,289
Natural gas production		28,337			56,362
Natural gas liquids production		12,366			27,970
Other operational income		2,160			1,209
Derivative income, net		3,128			—

Total operating revenue		153,498			223,830

Operating expenses:
Lease operating expenses		27,577			46,903
Transportation, processing and gathering expenses		17,703			14,626
Production taxes		2,515			3,062
Depreciation, depletion and amortization		86,422			82,646
Write-down of oil and gas properties		491,412			—
Accretion expense		6,409			7,555
Salaries, general and administrative expenses		17,007			16,329
Incentive compensation expense		1,563			3,134
Other operational expenses		84			424
Derivative expense, net		—			599

Total operating expenses		650,692			175,278

Income (loss) from operations		(497,194	)		48,552

Other (income) expenses:
Interest expense		10,365			8,357
Interest income		(122	)		(143	)
Other income		(143	)		(707	)

Total other expenses		10,100			7,507

Income (loss) before income taxes		(507,294	)		41,045

Provision (benefit) for income taxes:
Deferred		(179,906	)		15,102

Total income taxes		(179,906	)		15,102

Net income (loss)	($	327,388	)	$	25,943

Basic earnings (loss) per share	($	5.93	)	$	0.52
Diluted earnings (loss) per share	($	5.93	)	$	0.52
Average shares outstanding		55,181			49,013
Average shares outstanding assuming dilution		55,181			49,062

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 March 31,
	2015			2014
Net income (loss)	($	327,388	)	$	25,943
Other comprehensive loss, net of tax effect:
Derivatives		(8,858	)		(6,590	)
Foreign currency translation		(3,645	)		(499	)

Comprehensive income (loss)	($	339,891	)	$	18,854

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,
	2015			2014
Cash flows from operating activities:
Net income (loss)	($	327,388	)	$	25,943
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		86,422			82,646
Write-down of oil and gas properties		491,412			—
Accretion expense		6,409			7,555
Deferred income tax (benefit) provision		(179,906	)		15,102
Settlement of asset retirement obligations		(17,145	)		(9,842	)
Non-cash stock compensation expense		2,640			2,247
Non-cash derivative expense		1,511			448
Non-cash interest expense		4,318			4,070
Change in current income taxes		7,188			—
(Increase) decrease in accounts receivable		8,206			(18,602	)
Decrease in other current assets		1,883			100
Increase in inventory		—			(928	)
Increase (decrease) in accounts payable		(8,657	)		1,293
Increase in other current liabilities		6,889			5,820
Other		(260	)		(380	)

Net cash provided by operating activities		83,522			115,472

Cash flows from investing activities:
Investment in oil and gas properties		(169,895	)		(287,175	)
Proceeds from sale of oil and gas properties, net of expenses		—			51,954
Investment in fixed and other assets		(662	)		(1,654	)
Change in restricted funds		177,642			(358	)

Net cash provided by (used in) investing activities		7,085			(237,233	)

Cash flows from financing activities:
Proceeds from bank borrowings		5,000			—
Repayment of bank borrowings		(5,000	)		—
Deferred financing costs		—			(126	)
Net payments for share-based compensation		(2,991	)		(6,565	)

Net cash used in financing activities		(2,991	)		(6,691	)

Effect of exchange rate changes on cash		24			(11	)

Net change in cash and cash equivalents		87,640			(128,463	)
Cash and cash equivalents, beginning of period		74,488			331,224

Cash and cash equivalents, end of period	$	162,128		$	202,761

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, 2015 and for the three month periods ended March 31, 2015 and 2014 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, 2014 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, 2014 (our “2014 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 2014 Annual Report on Form 10-K. The results of operations for the three month period ended March 31, 2015 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,
	2015			2014
	(In thousands, except per share data)
Income (numerator):
*Basic:*
Net income (loss)	($	327,388	)	$	25,943
Net income attributable to participating securities		—			(537	)

Net income (loss) attributable to common stock—basic	($	327,388	)	$	25,406

*Diluted:*
Net income (loss)	($	327,388	)	$	25,943
Net income attributable to participating securities		—			(537	)

Net income (loss) attributable to common stock—diluted	($	327,388	)	$	25,406

Weighted average shares (denominator):
Weighted average shares—basic		55,181			49,013
Dilutive effect of stock options		—			49

Weighted average shares—diluted		55,181			49,062

Basic earnings (loss) per share	($	5.93	)	$	0.52

Diluted earnings (loss) per share	($	5.93	)	$	0.52

All outstanding stock options were considered antidilutive during the three months ended March 31, 2015 (approximately 204,000 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 totaled approximately 242,000 shares during the three months ended March 31, 2014.

During the three months ended March 31, 2015 and 2014, approximately 370,000 shares and 333,000 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 dilution in the diluted earnings per share computation. For the three months ended March 31, 2015, there was no dilutive effect on the diluted earnings per share computation because we had a net loss for such period. For the three months ended March 31, 2014, 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 period. For the three months ended March 31, 2015 and 2014, 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)

and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 4 – Long-Term Debt), such call options are antidilutive and therefore, were not included in the calculation of diluted earnings per share.

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 derivative transactions to secure a commodity price for a portion of our expected 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 2015 and 2016 oil and natural gas production from the Gulf Coast Basin. 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. 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, The Bank of Nova Scotia, Bank of America and Natixis.

The following table illustrates our derivative positions for calendar years 2015 and 2016 as of May 4, 2015:


	Fixed-Price Swaps (NYMEX)
	Natural Gas				Oil
	Daily Volume (MMBtus/d)		Swap Price ($)		Daily Volume (Bbls/d)		Swap Price ($)
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

During 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 6 – Divestitures), that GOM natural gas production would be sufficient to cover the GOM volumes hedged. Accordingly, we discontinued hedge accounting for three 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 March 31, 2015, we had accumulated other comprehensive income of $77.9 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of March 31, 2015. We believe that approximately $69.4 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 March 31, 2015 and December 31, 2014:

Fair Value of Derivatives Qualifying as Hedging Instruments at March 31, 2015


	(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	$	113.0	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts		14.0	Long-term liabilities: Fair value of derivative contracts		—

		$	127.0		$	—

Fair Value of Derivatives Qualifying as Hedging Instruments at December 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 derivative contracts	$	127.0	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts		14.3	Long-term liabilities: Fair value of derivative contracts		—

		$	141.3		$	—

The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three month periods ended March 31, 2015 and 2014:

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations

for the Three Months Ended March 31, 2015 and 2014


	(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)
	2015		2014			Location	2015		2014			Location	2015		2014
Commodity contracts	$	22.9	($	17.4	)	Operating revenue—oil/gas production	$	36.8	($	7.1	)	Derivative income (expense), net	$	0.9	($	0.6	)

Total	$	22.9	($	17.4	)		$	36.8	($	7.1	)		$	0.9	($	0.6	)

(a)

For the three months ended March 31, 2015, effective hedging contracts increased oil revenue by $34.0 million and increased gas revenue by $2.8 million. 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.

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 March 31, 2015 and December 31, 2014.

Fair Value of Derivatives Not Qualifying as Hedging Instruments


	(In millions)
Description	Balance Sheet Location	March 31, 2015		December 31, 2014
Commodity contracts	Current assets: Fair value of derivative contracts	$	11.2	$	12.1

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 month period ended March 31, 2015. During the three month period ended March 31, 2014, all of our derivatives qualified as hedging instruments.

Amount of Gain Recognized in Derivative Income


(In millions)
Description	Three Months Ended March 31, 2015
Commodity contracts:
Cash settlements	$	3.1
Change in fair value		(0.9	)

Total gains on non-qualifying hedges	$	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. As of March 31, 2015 and December 31, 2014, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

Note 4 – Long-Term Debt

Long-term debt consisted of the following at:


	March 31, 2015		December 31, 2014
	(In millions)
1³⁄₄% Senior Convertible Notes due 2017	$	269.7	$	266.0
7¹⁄₂% Senior Notes due 2022		775.0		775.0
Bank debt		—		—

Total long-term debt	$	1,044.7	$	1,041.0

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. On May 1, 2015, our borrowing base under the bank credit facility was reaffirmed at $500 million. As of March 31 and May 4, 2015, we had no outstanding borrowings under the bank credit facility, and $19.2 million of 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. As of March 31, 2015, the bank credit facility was 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, typically 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. If a reduction in our borrowing base were to fall below any outstanding balances under the bank credit facility plus any outstanding letters of credit, our agreement with the banks allows us one or more of three options to cure the borrowing base deficiency. We may (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments.

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 March 31, 2015.

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, 2015, our closing share price was $14.68. 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 March 31, 2015, the carrying amount of the liability component of the 2017 Convertible Notes was $269.7 million. During the three months ended March 31, 2015, we recognized $3.6 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 $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 each of the three month periods ended March 31, 2015 and 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, 2015 is set forth below:


	Three Months Ended March 31, 2015
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	316.4
Liabilities settled		(17.1	)
Accretion expense		6.4

Asset retirement obligations as of the end of the period, including current portion	$	305.7

Note 6 – Divestitures

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. All of the proceeds from this sale were 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 were included in our balance sheet as restricted cash at December 31, 2014. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provided for deferral of taxable gain on these sales proceeds. We identified qualified replacement properties and had until January 27, 2015 to close on an acquisition of such properties in order to achieve deferral of our taxable gain. We did not close on such a transaction by January 27, 2015, and the funds were released from restrictions and reclassified to cash and cash equivalents at such date.

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, 2015 and December 31, 2014, 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, 2015:


	Fair Value Measurements at March 31, 2015
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)	$	8.8	$	8.8	$	—	$	—
Derivative contracts		138.2		—		138.2		—

Total	$	147.0	$	8.8	$	138.2	$	—

Fair Value Measurements at March 31, 2015

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

—

Total

—

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014:


	Fair Value Measurements at December 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 (Other assets)	$	8.4	$	8.4	$	—	$	—
Derivative contracts		153.5		—		153.5		—

Total	$	161.9	$	8.4	$	153.5	$	—

Fair Value Measurements at December 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)

Derivative contracts

—

Total

—

The fair value of cash and cash equivalents approximated book value at March 31, 2015 and December 31, 2014. As of March 31, 2015 and December 31, 2014, the fair value of the liability component of the 2017 Convertible Notes was approximately $261.0 million and $252.6 million, respectively. As of March 31, 2015 and December 31, 2014, the fair value of the 7¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) was approximately $703.3 million and $664.6 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, 2015 and December 31, 2014. 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, 2015 and 2014 were as follows (in millions):


	Cash Flow Hedges			Foreign Currency Items			Total
For the Three Months Ended March 31, 2015
Beginning balance, net of tax	$	86.8		($	3.5	)	$	83.3

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		22.9			—			22.9
Foreign currency translations		—			(3.6	)		(3.6	)
Income tax effect		(8.2	)		—			(8.2	)

Net of tax		14.7			(3.6	)		11.1

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		36.8			—			36.8
Income tax effect		(13.2	)		—			(13.2	)

Net of tax		23.6			—			23.6

Other comprehensive income (loss), net of tax		(8.9	)		(3.6	)		(12.5	)

Ending balance, net of tax	$	77.9		($	7.1	)	$	70.8


	Cash Flow Hedges			Foreign Currency Items			Total
For the Three Months Ended March 31, 2014
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 income (loss), net of tax		(6.6	)		(0.5	)		(7.1	)

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

Note 9 – 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 (adjusted for hedges and 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 March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491.4 million based on twelve month average prices, net of applicable differentials, of $78.99 per barrel of oil, $2.96 per Mcf of natural gas and $28.82 per barrel of natural gas liquids (“NGLs”). The write-down was decreased by $28.7 million as a result of hedges.

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, 2015 and December 31, 2014, were $44.2 million and $36.6 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 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.

On August 2, 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 alleged that Stone was obligated to pay Kimmeridge (1) $1,118,878 for brokerage costs incurred pursuant to a letter of understanding, and (2) $17,253,941 pursuant to a letter of intent which, according to Kimmeridge’s pleadings, required Stone to negotiate in good faith and close an acquisition of mineral interests in the Illinois basin. The court granted summary judgment in favor of Stone, limiting damages on Kimmeridge’s $17,253,941 claim to $1,000,000 and reducing Stone’s exposure at trial for both claims to $2,118,878. On April 29, 2015, Stone and Kimmeridge agreed to a preliminary settlement of both claims within the previously disclosed range of loss. Final settlement is subject to the execution of definitive settlement documents.

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, 2015 and December 31, 2014 and for the three month periods ended March 31, 2015 and 2014 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, 2015

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	131,936		$	30,015		$	177		$	—		$	162,128
Accounts receivable		102,556			42,014			30			(32,450	)		112,150
Fair value of derivative contracts		—			124,192			—			—			124,192
Current income tax receivable		24			—			—			—			24
Inventory		3,426			283			—			—			3,709
Other current assets		6,230			—			4			—			6,234

Total current assets		244,172			196,504			211			(32,450	)		408,437
Oil and gas properties, full cost method:
Proved		1,716,567			7,171,265			—			—			8,887,832
Less: accumulated DD&A		(1,502,385	)		(6,043,837	)		—			—			(7,546,222	)

Net proved oil and gas properties		214,182			1,127,428			—			—			1,341,610
Unevaluated		297,075			261,172			44,220			—			602,467
Other property and equipment, net		31,828			—			—			—			31,828
Fair value of derivative contracts		—			13,966			—			—			13,966
Other assets, net		21,692			1,080			1,900			—			24,672
Investment in subsidiary		1,068,365			—			46,161			(1,114,526	)		—

Total assets	$	1,877,314		$	1,600,150		$	92,492		($	1,146,976	)	$	2,422,980

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	30,986		$	61,410		$	8,200		($	32,450	)	$	68,146
Undistributed oil and gas proceeds		25,188			1,014			—			—			26,202
Accrued interest		22,243			—			—			—			22,243
Deferred taxes *		335			23,043			—			—			23,378
Asset retirement obligations		—			60,837			—			—			60,837
Other current liabilities		39,483			803			—			—			40,286

Total current liabilities		118,235			147,107			8,200			(32,450	)		241,092
Long-term debt		1,044,675			—			—			—			1,044,675
Deferred taxes *		(83,458	)		181,652			—			—			98,194
Asset retirement obligations		3,678			241,157			—			—			244,835
Other long-term liabilities		31,604			—			—			—			31,604

Total liabilities		1,114,734			569,916			8,200			(32,450	)		1,660,400

Commitments and contingencies
Stockholders’ equity:
Common stock		553			—			—			—			553
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,634,171			1,363,981			98,507			(1,462,488	)		1,634,171
Accumulated earnings (deficit)		(942,096	)		(411,672	)		12			411,660			(942,096	)
Accumulated other comprehensive income (loss)		70,812			77,925			(14,227	)		(63,698	)		70,812

Total stockholders’ equity		762,580			1,030,234			84,292			(1,114,526	)		762,580

Total liabilities and stockholders’ equity	$	1,877,314		$	1,600,150		$	92,492		($	1,146,976	)	$	2,422,980

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

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2014

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	72,886		$	1,450		$	152		$	—		$	74,488
Restricted cash		177,647			—			—			—			177,647
Accounts receivable		73,711			46,615			33			—			120,359
Fair value of derivative contracts		—			139,179			—			—			139,179
Current income tax receivable		7,212			—			—			—			7,212
Deferred taxes *		4,095			—			—			(4,095	)		—
Inventory		1,011			2,698			—			—			3,709
Other current assets		8,112			—			6			—			8,118

Total current assets		344,674			189,942			191			(4,095	)		530,712
Oil and gas properties, full cost method:
Proved		1,689,802			7,127,466			—			—			8,817,268
Less: accumulated DD&A		(970,387	)		(6,000,244	)		—			—			(6,970,631	)

Net proved oil and gas properties		719,415			1,127,222			—			—			1,846,637
Unevaluated		289,556			241,230			36,579			—			567,365
Other property and equipment, net		32,340			—			—			—			32,340
Fair value of derivative contracts		—			14,333			—			—			14,333
Other assets, net		20,857			1,360			5,007			—			27,224
Investment in subsidiary		1,050,546			—			41,638			(1,092,184	)		—

Total assets	$	2,457,388		$	1,574,087		$	83,415		($	1,096,279	)	$	3,018,611

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	74,756		$	57,873		$	—		$	—		$	132,629
Undistributed oil and gas proceeds		22,158			1,074			—			—			23,232
Accrued interest		9,022			—			—			—			9,022
Deferred taxes *		—			24,214			—			(4,095	)		20,119
Asset retirement obligations		—			69,400			—			—			69,400
Other current liabilities		49,306			199			—			—			49,505

Total current liabilities		155,242			152,760			—			(4,095	)		303,907
Long-term debt		1,041,035			—			—			—			1,041,035
Deferred taxes *		117,206			169,137			—			—			286,343
Asset retirement obligations		3,588			243,421			—			—			247,009
Other long-term liabilities		38,714			—			—			—			38,714

Total liabilities		1,355,785			565,318			—			(4,095	)		1,917,008

Commitments and contingencies
Stockholders’ equity:
Common stock		549			—			—			—			549
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,633,307			1,362,684			90,339			(1,453,023	)		1,633,307
Accumulated earnings (deficit)		(614,708	)		(440,699	)		12			440,687			(614,708	)
Accumulated other comprehensive income (loss)		83,315			86,784			(6,936	)		(79,848	)		83,315

Total stockholders’ equity		1,101,603			1,008,769			83,415			(1,092,184	)		1,101,603

Total liabilities and stockholders’ equity	$	2,457,388		$	1,574,087		$	83,415		($	1,096,279	)	$	3,018,611

*	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 MARCH 31, 2015

(In thousands)


	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	4,350		$	103,157		$	—		$	—		$	107,507
Natural gas production		16,617			11,720			—			—			28,337
Natural gas liquids production		9,879			2,487			—			—			12,366
Other operational income		2,160			—			—			—			2,160
Derivative income, net		—			3,128			—			—			3,128

Total operating revenue		33,006			120,492			—			—			153,498

Operating expenses:
Lease operating expenses		4,976			22,601			—			—			27,577
Transportation, processing and gathering expenses		16,108			1,595			—			—			17,703
Production taxes		2,198			317			—			—			2,515
Depreciation, depletion, amortization		42,112			44,310			—			—			86,422
Write-down of oil and gas properties		491,412			—			—			—			491,412
Accretion expense		91			6,318			—			—			6,409
Salaries, general and administrative		17,001			1			5			—			17,007
Incentive compensation expense		1,563			—			—			—			1,563
Other operational expense		84			—			—			—			84

Total operating expenses		575,545			75,142			5			—			650,692

Income (loss) from operations		(542,539	)		45,350			(5	)		—			(497,194	)

Other (income) expenses:
Interest expense		10,344			21			—			—			10,365
Interest income		(101	)		(16	)		(5	)		—			(122	)
Other income		(133	)		(10	)		—			—			(143	)
Income from investment in subsidiaries		(29,027	)		—			—			29,027			—

Total other (income) expenses		(18,917	)		(5	)		(5	)		29,027			10,100

Income (loss) before taxes		(523,622	)		45,355			—			(29,027	)		(507,294	)

Provision (benefit) for income taxes:
Deferred		(196,234	)		16,328			—			—			(179,906	)

Total income taxes		(196,234	)		16,328			—			—			(179,906	)

Net income (loss)	($	327,388	)	$	29,027		$	—		($	29,027	)	($	327,388	)

Comprehensive income (loss)	($	339,891	)	$	29,027		$	—		($	29,027	)	($	339,891	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

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
Natural 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:
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 CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2015

(In thousands)


	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	($	327,388	)	$	29,027		$	—		($	29,027	)	($	327,388	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		42,112			44,310			—			—			86,422
Write-down of oil and gas properties		491,412			—			—			—			491,412
Accretion expense		91			6,318			—			—			6,409
Deferred income tax (benefit) provision		(196,234	)		16,328			—			—			(179,906	)
Settlement of asset retirement obligations		(1	)		(17,144	)		—			—			(17,145	)
Non-cash stock compensation expense		2,640			—			—			—			2.640
Non-cash derivative expense		—			1,511			—			—			1,511
Non-cash interest expense		4,318			—			—			—			4,318
Change in current income taxes		7,188			—			—			—			7,188
Non-cash income from investment in subsidiaries		(29,027	)		—			—			29,027			—
Change in intercompany receivables/payables		(33,748	)		25,548			8,200			—			—
Decrease in accounts receivable		3,606			4,600			—			—			8,206
Decrease in other current assets		1,881			—			2			—			1,883
(Increase) decrease in inventory		(2,415	)		2,415			—			—			—
Decrease in accounts payable		(1,007	)		(7,650	)		—			—			(8,657	)
Increase in other current liabilities		6,347			542			—			—			6,889
Other		(249	)		(11	)		—			—			(260	)

Net cash (used in) provided by operating activities		(30,474	)		105,794			8,202			—			83,522

Cash flows from investing activities:
Investment in oil and gas properties		(84,470	)		(77,229	)		(8,196	)		—			(169,895	)
Investment in fixed and other assets		(662	)		—			—			—			(662	)
Change in restricted funds		177,647			—			(5	)		—			177,642
Investment in subsidiaries		—			—			(8,168	)		8,168			—

Net cash provided by (used in) investing activities		92,515			(77,229	)		(16,369	)		8,168			7,085

Cash flows from financing activities:
Proceeds from bank borrowings		5,000			—			—			—			5,000
Repayments of bank borrowings		(5,000	)		—			—			—			(5,000	)
Equity proceeds from parent		—			—			8,168			(8,168	)		—
Net payments for share-based compensation		(2,991	)		—			—			—			(2,991	)

Net cash (used in) provided by financing activities		(2,991	)		—			8,168			(8,168	)		(2,991	)

Effect of exchange rate changes on cash		—			—			24			—			24

Net change in cash and cash equivalents		59,050			28,565			25			—			87,640
Cash and cash equivalents, beginning of period		72,886			1,450			152			—			74,488

Cash and cash equivalents, end of period	$	131,936		$	30,015		$	177		$	—		$	162,128

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 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

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 2014 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 acquisition or 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 2014 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2014 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 2014 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 GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in the area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus Shale in Appalachia.

Critical Accounting Estimates

Our 2014 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 2014 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 2014 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

Declining Commodity Prices – We experienced a significant decline in oil and natural gas prices during the second half of 2014 and the first quarter of 2015. This has resulted in reduced revenue and cash flows and contributed to ceiling test write-downs of our U.S. oil and gas properties in 2014 and at March 31, 2015. It has also caused us to reduce our planned capital expenditures budget for 2015. Continued low commodity prices or further declines in 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 and could have a material adverse impact on future cash flows, substantially reduce the available borrowings under our bank credit facility and constrain capital budgets beyond 2015.

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.

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, 2015 are $44.2 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 operations.

Liquidity and Capital Resources

As of May 4, 2015, we had $480.8 million of availability under our bank credit facility and cash on hand of approximately $162.5 million. Our capital expenditure budget for 2015 has been set at $450 million, which assumes planned sales of minority working interests in certain targeted assets. The budget excludes material divestitures and acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest. Based on our current 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 our 2015 capital expenditure budget with cash flows from operating activities and cash on hand. Additionally, it is possible that due to our inability to successfully execute planned sales of minority working interests or defer certain expenditures, continued low commodity prices or further declines in commodity prices or other factors, a portion of our 2015 capital expenditure budget will require financing from borrowings under our bank credit facility or other sources. Accordingly, we may consider accessing the public or private markets as funding sources to provide additional capital.

Cash Flows and Working Capital. Net cash provided by operating activities totaled $83.5 million during the three months ended March 31, 2015 compared to $115.5 million during the comparable period in 2014.

Net cash provided by investing activities totaled $7.1 million during the three months ended March 31, 2015, which primarily represents our investment in oil and gas properties of $169.9 million, offset by $177.6 million of previously restricted proceeds from the sale of oil and gas properties. 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 gas properties of $287.2 million offset by proceeds from the sale of oil and gas properties of $52.0 million.

Net cash used in financing activities totaled $3.0 million and $6.7 million during the three months ended March 31, 2015 and 2014, respectively, which primarily represents net payments for share-based compensation. During the three months ended March 31, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility.

We had working capital at March 31, 2015 of $167.3 million.

Capital Expenditures. During the three months ended March 31, 2015, additions to oil and gas property costs of $105.7 million included $3.3 million of lease and property acquisition costs, $8.5 million of capitalized SG&A expenses (inclusive of incentive compensation) and $10.8 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. On May 1, 2015, our borrowing base under the bank credit facility was reaffirmed at $500 million. As of March 31 and May 4, 2015, we had no outstanding borrowings under the bank credit facility, and $19.2 million of letters of credit had been issued pursuant to the bank credit facility, leaving $480.8 million of availability under the bank credit facility. The bank credit facility is guaranteed by all of our material subsidiaries.

The borrowing base under the bank credit facility is redetermined semi-annually, typically 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 the assets of Stone and its material subsidiaries. They 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 March 31, 2015, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.55 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 10.16 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 March 31, 2015.

Contractual Obligations and Other Commitments

We have various contractual obligations and other commitments in the normal course of operations. For further information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Other Commitments” in our 2014 Annual Report on Form 10-K. There have been no material changes to this disclosure during the three months ended March 31, 2015.

Results of Operations

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


	Three Months Ended March 31,
	2015		2014		Variance			% Change
Production:
Oil (MBbls)		1,622		1,418		204			14	%
Natural gas (MMcf)		11,157		12,641		(1,484	)		(12	%)
NGLs (MBbls)		683		510		173			34	%
Oil, natural gas and NGLs (MMcfe)		24,987		24,209		778			3	%
Revenue data (in thousands): (1)
Oil revenue	$	107,507	$	138,289	($	30,782	)		(22	%)
Natural gas revenue		28,337		56,362		(28,025	)		(50	%)
NGLs revenue		12,366		27,970		(15,604	)		(56	%)

Total oil, natural gas and NGL revenue	$	148,210	$	222,621	($	74,411	)		(33	%)
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	45.31	$	99.27	($	53.96	)		(54	%)
Natural gas (per Mcf)		2.29		4.82		(2.53	)		(52	%)
NGLs (per Bbl)		18.11		54.84		(36.73	)		(67	%)
Oil, natural gas and NGLs (per Mcfe)		4.46		9.49		(5.03	)		(53	%)
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	66.28	$	97.52	($	31.24	)		(32	%)
Natural gas (per Mcf)		2.54		4.46		(1.92	)		(43	%)
NGLs (per Bbl)		18.11		54.84		(36.73	)		(67	%)
Oil, natural gas and NGLs (per Mcfe)		5.93		9.20		(3.27	)		(36	%)
Expenses (per Mcfe):
Lease operating expenses	$	1.10	$	1.94	($	0.84	)		(43	%)
Transportation, processing and gathering expenses		0.71		0.60		0.11			18	%
SG&A expenses (2)		0.68		0.67		0.01			1	%
DD&A expense on oil and gas properties		3.41		3.38		0.03			1	%

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

(2)	Excludes incentive compensation expense.

Net Income. During the three months ended March 31, 2015, we reported a net loss totaling approximately $327.4 million, or $5.93 per share, compared to net income for the three months ended March 31, 2014 of $25.9 million, or $0.52 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 March 31, 2015, we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $491.4 million ($314.5 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 month periods’ results was also due to the following components:

Production. During the three months ended March 31, 2015, total production volumes increased to 25.0 Bcfe compared to 24.2 Bcfe produced during the comparable 2014 period, representing a 3% increase. Oil production during the three months ended March 31, 2015 totaled approximately 1,622,000 Bbls compared to 1,418,000 Bbls produced during the comparable 2014 period. Natural gas production totaled 11.2 Bcf during the three months ended March 31, 2015 compared to 12.6 Bcf during the comparable 2014 period. NGL production during the three months ended March 31, 2015 totaled approximately 683,000 Bbls compared to 510,000 Bbls produced during the comparable 2014 period.

The increase in oil volumes was primarily attributable to production from our deepwater Cardona wells, which began producing late in the fourth quarter of 2014. During the three months ended March 31, 2015, natural gas and NGL volumes were higher at our Mary and Heather fields, as compared to the comparable 2014 period, due to continued development operations. These increases, however, were offset by decreases in production resulting from the divestitures of certain of our non-core GOM conventional shelf properties during 2014.

Prices. Prices realized during the three months ended March 31, 2015 averaged $66.28 per Bbl of oil, $2.54 per Mcf of natural gas and $18.11 per Bbl of NGLs, or 36% lower, on an Mcfe basis, than average realized prices of $97.52 per Bbl of oil, $4.46 per Mcf of natural gas and $54.84 per Bbl of NGLs during the comparable 2014 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 increased our average realized natural gas price by $0.25 per Mcf and increased our average realized oil price by $20.97 per Bbl during the three months ended March 31, 2015. During the three months ended March 31, 2014, 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.

Revenue. Oil, natural gas and NGL revenue was $148.2 million during the three months ended March 31, 2015 compared to $222.6 million during the comparable period of 2014. The decrease in total revenue for the three months ended March 31, 2015 was primarily due to a 36% decrease in average realized prices. The decrease was also attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014.

Derivative Income/Expense. Net derivative income for the three months ended March 31, 2015 totaled $3.1 million, comprised of $4.6 million of income from cash settlements and $1.5 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended March 31, 2014, net derivative expense totaled $0.6 million, comprised of $0.2 million of expense from cash settlements and $0.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.

Expenses. Lease operating expenses during the three months ended March 31, 2015 and 2014 totaled $27.6 million and $46.9 million, respectively. On a unit of production basis, lease operating expenses were $1.10 per Mcfe and $1.94 per Mcfe for the three months ended March 31, 2015 and 2014, respectively. The decrease in lease operating expenses during the three months ended March 31, 2015 was primarily attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014 as well as recent service cost reductions.

Transportation, processing and gathering expenses during the three months ended March 31, 2015 and 2014 totaled $17.7 million and $14.6 million, respectively, or $0.71 per Mcfe and $0.60 per Mcfe, respectively. The increase was attributable to higher gas, NGL and condensate volumes in Appalachia, where processing and gathering costs are higher.

DD&A expense on oil and gas properties for the three months ended March 31, 2015 totaled $85.2 million compared to $81.8 million during the comparable period of 2014. On a unit of production basis, DD&A expense was $3.41 per Mcfe and $3.38 per Mcfe during the three months ended March 31, 2015 and 2014, respectively.

SG&A expenses (exclusive of incentive compensation) for the three months ended March 31, 2015 were $17.0 million compared to $16.3 million for the three months ended March 31, 2014. On a unit of production basis, SG&A expenses were $0.68 per Mcfe and $0.67 per Mcfe for the three months ended March 31, 2015 and 2014, respectively.

For the three months ended March 31, 2015 and 2014, incentive compensation expense totaled $1.6 million and $3.1 million, respectively. These amounts related to the accrual of estimated incentive compensation bonuses, which are calculated based on the projected achievement of certain strategic objectives for each fiscal year.

Interest expense for the three months ended March 31, 2015 totaled $10.4 million, net of $10.8 million of capitalized interest, compared to interest expense of $8.4 million, net of $12.8 million of capitalized interest, during the comparable 2014 period. The increase in interest expense was primarily the result of a decrease in the amount of interest capitalized to oil and gas properties.

For the three months ended March 31, 2015 and 2014, we recorded an income tax (benefit) provision of ($179.9) million and $15.1 million, respectively. The income tax benefit recorded for the three months ended March 31, 2015 was a result of our loss before income taxes attributable to the ceiling test write-down.

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. For the three months ended March 31, 2015, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $5.7 million impact on our revenues. 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 have hedged approximately 50% of our estimated 2015 production from estimated proved reserves and 13% 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 2014 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, 2015, 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, 2015. 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, 2015 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, 2015 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 plaintiffs opposed removal. The Plaquemines Parish matter was remanded to state court, and it is anticipated that the other matters involving Stone will also be remanded to state court. Stone is actively investigating and evaluating the allegations.

On July 26, 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.

On August 2, 2013, 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 alleged that Stone was obligated to pay Kimmeridge (1) $1,118,878 for brokerage costs incurred pursuant to a letter of understanding, and (2) $17,253,941 pursuant to a letter of intent which, according to Kimmeridge’s pleadings, required Stone to negotiate in good faith and close an acquisition of mineral interests in the Illinois basin. The court granted summary judgment in favor of Stone, limiting damages on Kimmeridge’s $17,253,941 claim to $1,000,000 and reducing Stone’s exposure at trial for both claims to $2,118,878. On April 29, 2015, Stone and Kimmeridge agreed to a preliminary settlement of both claims within the previously disclosed range of loss. Final settlement is subject to the execution of definitive settlement documents.

On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. In September 2014, Stone sold its interest in the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”), and PADEP approved the transfer on November 24, 2014, after Stone’s receipt of the NOV. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. The PADEP may impose a penalty in this matter, but the amount of that penalty cannot be reasonably estimated at this time. Southwestern is conducting remediation activities at the well site, and Stone continues to monitor those activities.

Also on November 17, 2014, the Environmental Protection Agency (“EPA”) issued two administrative compliance orders relating, respectively, to Stone’s Conley and Tuttle Impoundment Sites in West Virginia. The EPA compliance orders (1) allege that Stone placed fill material in jurisdictional waters without first obtaining a Clean Water Act permit and (2) order Stone to submit a wetland and stream delineation report. On December 8, 2014, Stone received a request from the EPA for additional information about the sites. Stone responded to this request and submitted site delineations. The EPA may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.

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 2014 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, 2015:


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, 2015		210,388	$	14.22		—
February 1 – February 28, 2015		—		—		—
March 1 – March 31, 2015		—		—		—

		210,388	$	14.22		—	$	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, 2015.

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.


	STONE ENERGY CORPORATION

Date: May 7, 2015	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)).

*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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