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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended June 30, 2015

or

 

¨	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.

 

Large accelerated filer		x		Accelerated filer		¨
Non-accelerated filer		¨  (Do not check if a smaller reporting company)		Smaller reporting company		¨

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 August 5, 2015, there were 57,249,506 shares of the registrant’s common stock, par value $.01 per share, outstanding.

 

 

 

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TABLE OF CONTENTS

 

				Page
PART I – FINANCIAL INFORMATION
Item 1.		Financial Statements:
		Condensed Consolidated Balance Sheet as of June 30, 2015 and December 31, 2014			1
		Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2015 and 2014			2
		Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2015 and 2014			3
		Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 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			23
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			30
Item 4.		Controls and Procedures			30
PART II – OTHER INFORMATION
Item 1.		Legal Proceedings			32
Item 1A.		Risk Factors			33
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			33
Item 6.		Exhibits			34
		Signatures			35
		Exhibit Index			36

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

 

		June 30,				December 31,
		2015				2014
		(Unaudited)				(Note 1)
Assets
Current assets:
Cash and cash equivalents		$	141,655			$	74,488
Restricted cash			—				177,647
Accounts receivable			68,706				120,359
Fair value of derivative contracts			74,319				139,179
Current income tax receivable			6				7,212
Inventory			3,709				3,709
Other current assets			10,076				8,118
Total current assets			298,471				530,712
Oil and gas properties, full cost method of accounting:
Proved			9,074,425				8,817,268
Less: accumulated depreciation, depletion and amortization			(7,846,343	)			(6,970,631	)
Net proved oil and gas properties			1,228,082				1,846,637
Unevaluated			529,589				567,365
Other property and equipment, net			30,736				32,340
Fair value of derivative contracts			8,231				14,333
Other assets, net			28,082				27,224
Total assets		$	2,123,191			$	3,018,611
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		$	69,423			$	132,629
Undistributed oil and gas proceeds			17,000				23,232
Accrued interest			9,027				9,022
Deferred taxes			7,065				20,119
Asset retirement obligations			56,176				69,400
Other current liabilities			46,780				49,505
Total current liabilities			205,471				303,907
Long-term debt			1,048,406				1,041,035
Deferred taxes			11,752				286,343
Asset retirement obligations			240,613				247,009
Other long-term liabilities			32,213				38,714
Total liabilities			1,538,455				1,917,008
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 150,000,000 shares; issued 55,283,825 and 54,884,542 shares, respectively			553				549
Treasury stock (16,582 shares, at cost)			(860	)			(860	)
Additional paid-in capital			1,639,389				1,633,307
Accumulated deficit			(1,095,002	)			(614,708	)
Accumulated other comprehensive income			40,656				83,315
Total stockholders’ equity			584,736				1,101,603
Total liabilities and stockholders’ equity		$	2,123,191			$	3,018,611

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

 

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Operating revenue:
Oil production		$	111,585			$	142,393			$	219,092			$	280,682
Natural gas production			26,907				46,667				55,244				103,029
Natural gas liquids production			11,033				15,936				23,399				43,906
Other operational income			—				2,050				1,792				3,047
Derivative income, net			—				—				2,427				—
Total operating revenue			149,525				207,046				301,954				430,664
Operating expenses:
Lease operating expenses			27,429				49,454				55,006				96,357
Transportation, processing and gathering expenses			19,940				14,098				37,643				28,724
Production taxes			1,827				3,257				4,342				6,319
Depreciation, depletion and amortization			77,951				92,835				164,373				175,481
Write-down of oil and gas properties			224,294				—				715,706				—
Accretion expense			6,408				7,733				12,817				15,288
Salaries, general and administrative expenses			16,418				16,637				33,425				32,966
Incentive compensation expense			1,264				3,903				2,827				7,037
Other operational expenses			1,454				—				1,170				212
Derivative expense, net			701				2,516				—				3,115
Total operating expenses			377,686				190,433				1,027,309				365,499
Income (loss) from operations			(228,161	)			16,613				(725,355	)			65,165
Other (income) expenses:
Interest expense			10,472				9,913				20,837				18,270
Interest income			(66	)			(193	)			(188	)			(336	)
Other income			(613	)			(722	)			(756	)			(1,429	)
Other expense			—				179				—				179
Total other expenses			9,793				9,177				19,893				16,684
Income (loss) before income taxes			(237,954	)			7,436				(745,248	)			48,481
Provision (benefit) for income taxes:
Deferred			(85,048	)			2,992				(264,954	)			18,094
Total income taxes			(85,048	)			2,992				(264,954	)			18,094
Net income (loss)		($	152,906	)		$	4,444			($	480,294	)		$	30,387
Basic earnings (loss) per share		($	2.77	)		$	0.08			($	8.70	)		$	0.59
Diluted earnings (loss) per share		($	2.77	)		$	0.08			($	8.70	)		$	0.59
Average shares outstanding			55,251				52,050				55,216				50,540
Average shares outstanding assuming dilution			55,251				52,373				55,216				50,727

The accompanying notes are an integral part of this statement.

 

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Net income (loss)		($	152,906	)		$	4,444			($	480,294	)		$	30,387
Other comprehensive income (loss), net of tax effect:
Derivatives			(31,480	)			(9,765	)			(40,338	)			(16,355	)
Foreign currency translation			1,324				755				(2,321	)			256
Comprehensive income (loss)		($	183,062	)		($	4,566	)		($	522,953	)		$	14,288

The accompanying notes are an integral part of this statement.

 

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)

 

		Six Months Ended June 30,
		2015				2014
Cash flows from operating activities:
Net income (loss)		($	480,294	)		$	30,387
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			164,373				175,481
Write-down of oil and gas properties			715,706				—
Accretion expense			12,817				15,288
Deferred income tax (benefit) provision			(264,954	)			18,094
Settlement of asset retirement obligations			(35,923	)			(24,915	)
Non-cash stock compensation expense			6,028				5,358
Non-cash derivative expense			7,931				2,697
Non-cash interest expense			8,737				8,229
Change in current income taxes			7,206				(6	)
(Increase) decrease in accounts receivable			23,047				(25,524	)
Increase in other current assets			(1,959	)			(82	)
Increase (decrease) in accounts payable			(7,826	)			1,843
Increase (decrease) in other current liabilities			(8,720	)			50,785
Other			(504	)			(675	)
Net cash provided by operating activities			145,665				256,960
Cash flows from investing activities:
Investment in oil and gas properties			(264,355	)			(517,904	)
Proceeds from sale of oil and gas properties, net of expenses			10,100				51,955
Investment in fixed and other assets			(727	)			(3,896	)
Change in restricted funds			179,475				(356	)
Net cash used in investing activities			(75,507	)			(470,201	)
Cash flows from financing activities:
Proceeds from bank borrowings			5,000				—
Repayment of bank borrowings			(5,000	)			—
Net proceeds from issuance of common stock			—				226,036
Deferred financing costs			—				(3,167	)
Net payments for share-based compensation			(3,069	)			(6,948	)
Net cash provided by (used in) financing activities			(3,069	)			215,921
Effect of exchange rate changes on cash			78				(18	)
Net change in cash and cash equivalents			67,167				2,662
Cash and cash equivalents, beginning of period			74,488				331,224
Cash and cash equivalents, end of period		$	141,655			$	333,886

The accompanying notes are an integral part of this statement.

 

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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 June 30, 2015 and for the three and six month periods ended June 30, 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 and six month periods ended June 30, 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 June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
		(In thousands, except per share data)
Income (numerator):
Basic:
Net income (loss)		($	152,906	)		$	4,444			($	480,294	)		$	30,387
Net income attributable to participating securities			—				(111	)			—				(698	)
Net income (loss) attributable to common stock - basic		($	152,906	)		$	4,333			($	480,294	)		$	29,689
Diluted:
Net income (loss)		($	152,906	)		$	4,444			($	480,294	)		$	30,387
Net income attributable to participating securities			—				(111	)			—				(697	)
Net income (loss) attributable to common stock - diluted		($	152,906	)		$	4,333			($	480,294	)		$	29,690
Weighted average shares (denominator):
Weighted average shares - basic			55,251				52,050				55,216				50,540
Dilutive effect of stock options			—				58				—				54
Dilutive effect of convertible notes			—				265				—				133
Weighted average shares - diluted			55,251				52,373				55,216				50,727
Basic earnings (loss) per share		($	2.77	)		$	0.08			($	8.70	)		$	0.59
Diluted earnings (loss) per share		($	2.77	)		$	0.08			($	8.70	)		$	0.59

All outstanding stock options were considered antidilutive during the three and six months ended June 30, 2015 (approximately 174,000 shares) because we had a net loss for such periods. Stock options that were considered antidilutive because the exercise price of the options exceeded the average price of our common stock totaled approximately 120,000 shares and 131,000 shares, respectively, during the three and six months ended June 30, 2014.

During the three months ended June 30, 2015 and 2014, approximately 29,000 shares and 40,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock by employees and nonemployee directors. During the six months ended June 30, 2015 and 2014, approximately 399,000 shares and 372,000 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. In May 2014, 5,750,000 shares of our common stock were issued in a public offering.

Because it is management’s stated intention to redeem the principal amount of our 1 ³⁄₄% 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 and six months ended June 30, 2015, there was no dilutive

 

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effect on the diluted earnings per share computation because we had a net loss for such periods. For the three months ended June 30, 2014, the average price of our common stock exceeded the effective conversion price for such notes, resulting in a dilutive effect on the diluted earnings per share computation for the three and six months ended June 30, 2014. For all periods presented, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 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 August 5, 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 June 30, 2015, we had accumulated other comprehensive income of $46.5 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of June 30, 2015. We believe that approximately $41.4 million, net of tax, of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

 

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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 June 30, 2015 and December 31, 2014:

 

Fair Value of Derivatives Qualifying as Hedging Instruments at June 30, 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		$	67.5			Current liabilities: Fair value of derivative contracts		$	—
		Long-term assets: Fair value of derivative contracts			8.2			Long-term liabilities: Fair value of derivative contracts			—
				$	75.7					$	—
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 tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and six months ended June 30, 2015 and 2014:

 

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Three Months Ended June 30, 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		($	18.8	)		($	26.0	)		Operating revenue - oil/gas production		$	30.4			($	9.2	)		Derivative income (expense), net		($	0.4	)		($	1.0	)
Total		($	18.8	)		($	26.0	)				$	30.4			($	9.2	)				($	0.4	)		($	1.0	)

 

(a)

For the three months ended June 30, 2015, effective hedging contracts increased oil revenue by $26.4 million and increased gas revenue by $4.0 million. For the three months ended June 30, 2014, effective hedging contracts decreased oil revenue by $6.1 million and decreased gas revenue by $3.1 million.

 

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Six Months Ended June 30, 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		$	4.1			($	43.4	)		Operating revenue - oil/gas production		$	67.2			($	16.3	)		Derivative income (expense), net		$	0.5			($	1.6	)
Total		$	4.1			($	43.4	)				$	67.2			($	16.3	)				$	0.5			($	1.6	)

 

(a)	For the six months ended June 30, 2015, effective hedging contracts increased oil revenue by $60.4 million and increased gas revenue by $6.8 million. For the six months ended June 30, 2014, effective hedging contracts decreased oil revenue by $8.6 million and decreased gas revenue by $7.7 million.

 

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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 June 30, 2015 and December 31, 2014:

 

Fair Value of Derivatives Not Qualifying as Hedging Instruments (In millions)
Description		Balance Sheet Location		June 30, 2015				December 31, 2014
Commodity contracts		Current assets: Fair value of derivative contracts		$	6.8			$	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 and six months ended June 30, 2015 and 2014.

 

Amount of Gain (Loss) Recognized in Derivative Income (Expense) (In millions)
		Three Months Ended June 30,								Six Months Ended June 30,
Description		2015				2014				2015				2014
Commodity contracts:
Cash settlements		$	4.1			$	—			$	7.2			$	—
Change in fair value			(4.4	)			(1.5	)			(5.3	)			(1.5	)
Total gains (losses) on non-qualifying hedges		($	0.3	)		($	1.5	)		$	1.9			($	1.5	)

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 June 30, 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:

 

		June 30, 2015				December 31, 2014
		(In millions)
1 3⁄4% Senior Convertible Notes due 2017		$	273.4			$	266.0
7 1⁄2% Senior Notes due 2022			775.0				775.0
Bank debt			—				—
Total long-term debt		$	1,048.4			$	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. The next redetermination of our borrowing base under the bank credit facility is expected in October 2015. As of June 30 and August 5, 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 June 30, 2015, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), SEO A LLC and SEO B LLC (collectively, the “Guarantor 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 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

 

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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 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 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 June 30, 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 June 30, 2015, our closing share price was $12.59. 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 June 30, 2015, the carrying amount of the liability component of the 2017 Convertible Notes was $273.4 million. During the three and six months ended June 30, 2015, we recognized $3.7 million and $7.4 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $0.7 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and six months ended June 30, 2014, we recognized $3.5 million and $6.8 million, respectively, of interest expense for the amortization of the discount and $0.3 million and $0.6 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and six months ended June 30, 2015, we recognized $1.3 million and $2.6 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and six months ended June 30, 2014, we recognized $1.3 million and $2.6 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

 

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Note 5 – Asset Retirement Obligations

The change in our asset retirement obligations during the six months ended June 30, 2015 is set forth below:

 

		Six Months Ended June 30, 2015
		(In millions)
Asset retirement obligations as of the beginning of the period, including current portion		$	316.4
Liabilities incurred			3.5
Liabilities settled			(35.9	)
Accretion expense			12.8
Asset retirement obligations as of the end of the period, including current portion		$	296.8

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 June 30, 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 June 30, 2015:

 

		Fair Value Measurements at June 30, 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			82.6				—				82.6				—
Total		$	91.4			$	8.8			$	82.6			$	—

 

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Fair Value Measurements at June 30, 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 June 30, 2015 and December 31, 2014. As of June 30, 2015 and December 31, 2014, the fair value of the liability component of the 2017 Convertible Notes was approximately $264.9 million and $252.6 million, respectively. As of June 30, 2015 and December 31, 2014, the fair value of the 7 ¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) was approximately $685.9 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, June 30, 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.

 

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Note 8 – Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component for the three and six months ended June 30, 2015 were as follows (in millions):

 

		Cash Flow Hedges				Foreign Currency Items				Total
For the Three Months Ended June 30, 2015
Beginning balance, net of tax		$	77.9			($	7.1	)		$	70.8
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives			(18.8	)			—				(18.8	)
Foreign currency translations			—				1.3				1.3
Income tax effect			6.9				—				6.9
Net of tax			(11.9	)			1.3				(10.6	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production			30.4				—				30.4
Income tax effect			(10.9	)			—				(10.9	)
Net of tax			19.5				—				19.5
Other comprehensive income (loss), net of tax			(31.4	)			1.3				(30.1	)
Ending balance, net of tax		$	46.5			($	5.8	)		$	40.7

 

		Cash Flow Hedges				Foreign Currency Items				Total
For the Six Months Ended June 30, 2015
Beginning balance, net of tax		$	86.8			($	3.5	)		$	83.3
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives			4.1				—				4.1
Foreign currency translations			—				(2.3	)			(2.3	)
Income tax effect			(1.3	)			—				(1.3	)
Net of tax			2.8				(2.3	)			0.5
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production			67.2				—				67.2
Income tax effect			(24.1	)			—				(24.1	)
Net of tax			43.1				—				43.1
Other comprehensive income (loss), net of tax			(40.3	)			(2.3	)			(42.6	)
Ending balance, net of tax		$	46.5			($	5.8	)		$	40.7

 

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

 

		Cash Flow Hedges				Foreign Currency Items				Total
For the Three Months Ended June 30, 2014
Beginning balance, net of tax		($	8.0	)		($	1.2	)		($	9.2	)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives			(26.0	)			—				(26.0	)
Foreign currency translations			—				0.8				0.8
Income tax effect			9.4				—				9.4
Net of tax			(16.6	)			0.8				(15.8	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production			(9.2	)			—				(9.2	)
Derivative expense, net			(1.5	)			—				(1.5	)
Income tax effect			3.9				—				3.9
Net of tax			(6.8	)			—				(6.8	)
Other comprehensive income (loss), net of tax			(9.8	)			0.8				(9.0	)
Ending balance, net of tax		($	17.8	)		($	0.4	)		($	18.2	)

 

		Cash Flow Hedges				Foreign Currency Items				Total
For the Six Months Ended June 30, 2014
Beginning balance, net of tax		($	1.4	)		($	0.7	)		($	2.1	)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives			(43.4	)			—				(43.4	)
Foreign currency translations			—				0.3				0.3
Income tax effect			15.7				—				15.7
Net of tax			(27.7	)			0.3				(27.4	)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production			(16.3	)			—				(16.3	)
Derivative expense, net			(1.5	)			—				(1.5	)
Income tax effect			6.5				—				6.5
Net of tax			(11.3	)			—				(11.3	)
Other comprehensive income (loss), net of tax			(16.4	)			0.3				(16.1	)
Ending balance, net of tax		($	17.8	)		($	0.4	)		($	18.2	)

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 June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179.1 million based on twelve month average prices, net of applicable differentials, of $68.68 per barrel of oil, $2.47 per Mcf of natural gas and $29.13 per barrel of natural gas liquids (“NGLs”). The write-down at June 30, 2015 was decreased by $47.8 million as a result of hedges. 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 NGLs. The write-down at March 31, 2015 was decreased by $28.7 million as a result of hedges.

 

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In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices over the last several months, we have suspended our business development effort in Canada. Accordingly, at June 30, 2015, we recognized a write-down of our Canadian oil and gas properties of $45.2 million.

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. During the three months ended June 30, 2015, Stone and Kimmeridge settled both claims for an amount within the previously disclosed range of loss (between $0 and $2,118,878).

 

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Note 11 – Guarantor Financial Statements

Our Guarantor Subsidiaries, Stone Offshore, SEO A LLC and SEO B LLC, are unconditional guarantors 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 June 30, 2015 and December 31, 2014 and for the three and six month periods ended June 30, 2015 and 2014 on an issuer (parent company), Guarantor Subsidiaries, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

JUNE 30, 2015

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents		$	116,427			$	25,034			$	194			$	—			$	141,655
Accounts receivable			38,735				243,846				31				(213,906	)			68,706
Fair value of derivative contracts			—				74,319				—				—				74,319
Current income tax receivable			6				—				—				—				6
Inventory			3,426				283				—				—				3,709
Other current assets			10,007				—				69				—				10,076
Total current assets			168,601				343,482				294				(213,906	)			298,471
Oil and gas properties, full cost method:
Proved			1,778,480				7,251,498				44,447				—				9,074,425
Less: accumulated DD&A			(1,724,404	)			(6,077,492	)			(44,447	)			—				(7,846,343	)
Net proved oil and gas properties			54,076				1,174,006				—				—				1,228,082
Unevaluated			300,360				227,067				2,162				—				529,589
Other property and equipment, net			30,736				—				—				—				30,736
Fair value of derivative contracts			—				8,231				—				—				8,231
Deferred taxes *			—				—				16,266				(16,266	)			—
Other assets, net			25,149				1,385				1,548				—				28,082
Investment in subsidiary			1,057,810				—				20,083				(1,077,893	)			—
Total assets		$	1,636,732			$	1,754,171			$	40,353			($	1,308,065	)		$	2,123,191
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		$	56,763			$	216,834			$	9,732			($	213,906	)		$	69,423
Undistributed oil and gas proceeds			16,093				907				—				—				17,000
Accrued interest			9,027				—				—				—				9,027
Deferred taxes *			298				6,767				—				—				7,065
Asset retirement obligations			—				56,176				—				—				56,176
Other current liabilities			46,724				56				—				—				46,780
Total current liabilities			128,905				280,740				9,732				(213,906	)			205,471
Long-term debt			1,048,406				—				—				—				1,048,406
Deferred taxes *			(161,285	)			189,303				—				(16,266	)			11,752
Asset retirement obligations			3,757				236,856				—				—				240,613
Other long-term liabilities			32,213				—				—				—				32,213
Total liabilities			1,051,996				706,899				9,732				(230,172	)			1,538,455
Commitments and contingencies
Stockholders’ equity:
Common stock			553				—				—				—				553
Treasury stock			(860	)			—				—				—				(860	)
Additional paid-in capital			1,639,389				1,367,434				100,023				(1,467,457	)			1,639,389
Accumulated deficit			(1,095,002	)			(366,607	)			(57,824	)			424,431				(1,095,002	)
Accumulated other comprehensive income (loss)			40,656				46,445				(11,578	)			(34,867	)			40,656
Total stockholders’ equity			584,736				1,047,272				30,621				(1,077,893	)			584,736
Total liabilities and stockholders’ equity		$	1,636,732			$	1,754,171			$	40,353			($	1,308,065	)		$	2,123,191

 

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

 

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CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2014

(In thousands)

 

		Parent				Guarantor Subsidiaries				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 our Guarantor Subsidiaries where related oil and gas properties reside.

 

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2015

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Operating revenue:
Oil production		$	6,504			$	105,081			$	—			$	—			$	111,585
Natural gas production			15,647				11,260				—				—				26,907
Natural gas liquids production			8,077				2,956				—				—				11,033
Total operating revenue			30,228				119,297				—				—				149,525
Operating expenses:
Lease operating expenses			5,111				22,318				—				—				27,429
Transportation, processing and gathering expenses			17,974				1,966				—				—				19,940
Production taxes			1,436				391				—				—				1,827
Depreciation, depletion, amortization			44,052				33,899				—				—				77,951
Write-down of oil and gas properties			179,125				—				45,169				—				224,294
Accretion expense			91				6,317				—				—				6,408
Salaries, general and administrative			16,398				—				20				—				16,418
Incentive compensation expense			1,264				—				—				—				1,264
Other operational expense			1,454				—				—				—				1,454
Derivative expense, net			—				701				—				—				701
Total operating expenses			266,905				65,592				45,189				—				377,686
Income (loss) from operations			(236,677	)			53,705				(45,189	)			—				(228,161	)
Other (income) expenses:
Interest expense			10,472				—				—				—				10,472
Interest income			(46	)			(19	)			(1	)			—				(66	)
Other income			(187	)			(423	)			(3	)			—				(613	)
(Income) loss from investment in subsidiaries			(16,147	)			—				28,918				(12,771	)			—
Total other (income) expenses			(5,908	)			(442	)			28,914				(12,771	)			9,793
Income (loss) before taxes			(230,769	)			54,147				(74,103	)			12,771				(237,954	)
Provision (benefit) for income taxes:
Deferred			(77,863	)			9,082				(16,267	)			—				(85,048	)
Total income taxes			(77,863	)			9,082				(16,267	)			—				(85,048	)
Net income (loss)		($	152,906	)		$	45,065			($	57,836	)		$	12,771			($	152,906	)
Comprehensive income (loss)		($	183,062	)		$	45,065			($	57,836	)		$	12,771			($	183,062	)

 

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2014

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Operating revenue:
Oil production		$	5,854			$	136,539			$	—			$	—			$	142,393
Natural gas production			20,800				25,867				—				—				46,667
Natural gas liquids production			10,219				5,717				—				—				15,936
Other operational income			1,880				170				—				—				2,050
Total operating revenue			38,753				168,293				—				—				207,046
Operating expenses:
Lease operating expenses			5,046				44,408				—				—				49,454
Transportation, processing and gathering expenses			10,456				3,642				—				—				14,098
Production taxes			1,903				1,354				—				—				3,257
Depreciation, depletion, amortization			30,385				62,450				—				—				92,835
Accretion expense			61				7,672				—				—				7,733
Salaries, general and administrative			16,639				—				(2	)			—				16,637
Incentive compensation expense			3,903				—				—				—				3,903
Derivative expense, net			—				2,516				—				—				2,516
Total operating expenses			68,393				122,042				(2	)			—				190,433
Income (loss) from operations			(29,640	)			46,251				2				—				16,613
Other (income) expenses:
Interest expense			9,880				33				—				—				9,913
Interest income			(146	)			(41	)			(6	)			—				(193	)
Other income			(192	)			(530	)			—				—				(722	)
Other expense			179				—				—				—				179
Income from investment in subsidiaries			(29,947	)			—				(8	)			29,955				—
Total other (income) expenses			(20,226	)			(538	)			(14	)			29,955				9,177
Income (loss) before taxes			(9,414	)			46,789				16				(29,955	)			7,436
Provision (benefit) for income taxes:
Deferred			(13,858	)			16,850				—				—				2,992
Total income taxes			(13,858	)			16,850				—				—				2,992
Net income		$	4,444			$	29,939			$	16			($	29,955	)		$	4,444
Comprehensive income (loss)		($	4,566	)		$	29,939			$	16			($	29,955	)		($	4,566	)

 

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2015

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Operating revenue:
Oil production		$	10,854			$	208,238			$	—			$	—			$	219,092
Natural gas production			32,264				22,980				—				—				55,244
Natural gas liquids production			17,956				5,443				—				—				23,399
Other operational income			1,792				—				—				—				1,792
Derivative income, net			—				2,427				—				—				2,427
Total operating revenue			62,866				239,088				—				—				301,954
Operating expenses:
Lease operating expenses			10,087				44,919				—				—				55,006
Transportation, processing and gathering expenses			34,082				3,561				—				—				37,643
Production taxes			3,634				708				—				—				4,342
Depreciation, depletion, amortization			86,164				78,209				—				—				164,373
Write-down of oil and gas properties			670,537				—				45,169				—				715,706
Accretion expense			182				12,635				—				—				12,817
Salaries, general and administrative			33,399				1				25				—				33,425
Incentive compensation expense			2,827				—				—				—				2,827
Other operational expense			1,170				—				—				—				1,170
Total operating expenses			842,082				140,033				45,194				—				1,027,309
Income (loss) from operations			(779,216	)			99,055				(45,194	)			—				(725,355	)
Other (income) expenses:
Interest expense			20,816				21				—				—				20,837
Interest income			(147	)			(35	)			(6	)			—				(188	)
Other income			(320	)			(433	)			(3	)			—				(756	)
(Income) loss from investment in subsidiaries			(45,174	)			—				28,918				16,256				—
Total other (income) expenses			(24,825	)			(447	)			28,909				16,256				19,893
Income (loss) before taxes			(754,391	)			99,502				(74,103	)			(16,256	)			(745,248	)
Provision (benefit) for income taxes:
Deferred			(274,097	)			25,410				(16,267	)			—				(264,954	)
Total income taxes			(274,097	)			25,410				(16,267	)			—				(264,954	)
Net income (loss)		($	480,294	)		$	74,092			($	57,836	)		($	16,256	)		($	480,294	)
Comprehensive income (loss)		($	522,953	)		$	74,092			($	57,836	)		($	16,256	)		($	522,953	)

 

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2014

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Operating revenue:
Oil production		$	12,490			$	268,192			$	—			$	—			$	280,682
Gas production			49,639				53,390				—				—				103,029
Natural gas liquids production			28,473				15,433				—				—				43,906
Other operational income			2,704				343				—				—				3,047
Total operating revenue			93,306				337,358				—				—				430,664
Operating expenses:
Lease operating expenses			9,059				87,298				—				—				96,357
Transportation, processing and gathering expenses			20,773				7,951				—				—				28,724
Production taxes			3,584				2,735				—				—				6,319
Depreciation, depletion, amortization			58,440				117,041				—				—				175,481
Accretion expense			129				15,159				—				—				15,288
Salaries, general and administrative			32,964				2				—				—				32,966
Incentive compensation expense			7,037				—				—				—				7,037
Other operational expenses			176				36				—				—				212
Derivative expense, net			—				3,115				—				—				3,115
Total operating expenses			132,162				233,337				—				—				365,499
Income (loss) from operations			(38,856	)			104,021				—				—				65,165
Other (income) expenses:
Interest expense			18,233				37				—				—				18,270
Interest income			(225	)			(99	)			(12	)			—				(336	)
Other income			(373	)			(1,056	)			—				—				(1,429	)
Other expense			179				—				—				—				179
Income from investment in subsidiaries			(67,292	)			—				(12	)			67,304				—
Total other (income) expenses			(49,478	)			(1,118	)			(24	)			67,304				16,684
Income before taxes			10,622				105,139				24				(67,304	)			48,481
Provision (benefit) for income taxes:
Deferred			(19,765	)			37,859				—				—				18,094
Total income taxes			(19,765	)			37,859				—				—				18,094
Net income		$	30,387			$	67,280			$	24			($	67,304	)		$	30,387
Comprehensive income		$	14,288			$	67,280			$	24			($	67,304	)		$	14,288

 

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2015

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Eliminations				Consolidated
Cash flows from operating activities:
Net income (loss)		($	480,294	)		$	74,092			($	57,836	)		($	16,256	)		($	480,294	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			86,164				78,209				—				—				164,373
Write-down of oil and gas properties			670,537				—				45,169				—				715,706
Accretion expense			182				12,635				—				—				12,817
Deferred income tax (benefit) provision			(274,097	)			25,410				(16,267	)			—				(264,954	)
Settlement of asset retirement obligations			(14	)			(35,909	)			—				—				(35,923	)
Non-cash stock compensation expense			6,028				—				—				—				6,028
Non-cash derivative expense			—				7,931				—				—				7,931
Non-cash interest expense			8,737				—				—				—				8,737
Change in current income taxes			7,206				—				—				—				7,206
Non-cash (income) expense from investment in subsidiaries			(45,174	)			—				28,918				16,256				—
Change in intercompany receivables/payables			15,070				(24,802	)			9,732				—				—
Decrease in accounts receivable			16,968				6,079				—				—				23,047
Increase in other current assets			(1,895	)			—				(64	)			—				(1,959	)
(Increase) decrease in inventory			(2,415	)			2,415				—				—				—
Decrease in accounts payable			(500	)			(7,326	)			—				—				(7,826	)
Decrease in other current liabilities			(8,409	)			(311	)			—				—				(8,720	)
Other			(71	)			(433	)			—				—				(504	)
Net cash (used in) provided by operating activities			(1,977	)			137,990				9,652				—				145,665
Cash flows from investing activities:
Investment in oil and gas properties			(128,333	)			(124,506	)			(11,516	)			—				(264,355	)
Proceeds from sale of oil and gas properties, net of expenses			—				10,100				—				—				10,100
Investment in fixed and other assets			(727	)			—				—				—				(727	)
Change in restricted funds			177,647				—				1,828				—				179,475
Investment in subsidiaries			—				—				(9,684	)			9,684				—
Net cash provided by (used in) investing activities			48,587				(114,406	)			(19,372	)			9,684				(75,507	)
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			—				—				9,684				(9,684	)			—
Net payments for share-based compensation			(3,069	)			—				—				—				(3,069	)
Net cash (used in) provided by financing activities			(3,069	)			—				9,684				(9,684	)			(3,069	)
Effect of exchange rate changes on cash			—				—				78				—				78
Net change in cash and cash equivalents			43,541				23,584				42				—				67,167
Cash and cash equivalents, beginning of period			72,886				1,450				152				—				74,488
Cash and cash equivalents, end of period		$	116,427			$	25,034			$	194			$	—			$	141,655

 

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2014

(In thousands)

 

		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Eliminations				Consolidated
Cash flows from operating activities:
Net income		$	30,387			$	67,280			$	24			($	67,304	)		$	30,387
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			58,440				117,041				—				—				175,481
Accretion expense			129				15,159				—				—				15,288
Deferred income tax (benefit) provision			(19,765	)			37,859				—				—				18,094
Settlement of asset retirement obligations			(82	)			(24,833	)			—				—				(24,915	)
Non-cash stock compensation expense			5,358				—				—				—				5,358
Non-cash derivative expense			—				2,697				—				—				2,697
Non-cash interest expense			8,229				—				—				—				8,229
Change in current income taxes			(6	)			—				—				—				(6	)
Non-cash income from investment in subsidiaries			(67,292	)			—				(12	)			67,304				—
Change in intercompany receivables/payables			(126,526	)			114,841				11,685				—				—
(Increase) decrease in accounts receivable			(42,216	)			16,692				—				—				(25,524	)
Increase in other current assets			(82	)			—				—				—				(82	)
Increase (decrease) in accounts payable			2,052				(209	)			—				—				1,843
Increase in other current liabilities			48,987				1,798				—				—				50,785
Other			381				(1,056	)			—				—				(675	)
Net cash (used in) provided by operating activities			(102,006	)			347,269				11,697				—				256,960
Cash flows from investing activities:
Investment in oil and gas properties			(121,836	)			(384,349	)			(11,719	)			—				(517,904	)
Proceeds from sale of oil and gas properties, net of expenses			9,777				42,178				—				—				51,955
Investment in fixed and other assets			(3,896	)			—				—				—				(3,896	)
Change in restricted funds			—				—				(356	)			—				(356	)
Investment in subsidiaries			—				—				(12,176	)			12,176				—
Net cash used in investing activities			(115,955	)			(342,171	)			(24,251	)			12,176				(470,201	)
Cash flows from financing activities:
Net proceeds from issuance of common stock			226,036				—				—				—				226,036
Deferred financing costs			(3,167	)			—				—				—				(3,167	)
Equity proceeds from parent			—				—				12,176				(12,176	)			—
Net payments for share-based compensation			(6,948	)			—				—				—				(6,948	)
Net cash provided by financing activities			215,921				—				12,176				(12,176	)			215,921
Effect of exchange rate on cash			—				—				(18	)			—				(18	)
Net change in cash and cash equivalents			(2,040	)			5,098				(396	)			—				2,662
Cash and cash equivalents, beginning of period			246,294				84,290				640				—				331,224
Cash and cash equivalents, end of period		$	244,254			$	89,388			$	244			$	—			$	333,886

 

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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, including further or sustained declines in the prices we receive for our oil and gas production;

 

•

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, liquidity and compliance with debt covenants;

 

•

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;

 

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•

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, with lower prices continuing throughout the first half of 2015, which has resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015. Additionally, the decline in commodity prices has adversely affected the value and estimated quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties at December 31, 2014, March 31, 2015 and June 30, 2015.

 

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Prolonged periods of depressed commodity prices significantly impact the value and estimated quantities of our proved reserve portfolio, assuming no other changes in our development plans. For example, using December 31, 2014 NYMEX 5-year forward strip prices, which were approximately 20% lower on an Mcfe basis than SEC-mandated prices, our December 31, 2014 estimated proved reserve volumes and the associated present value of future net revenues would have been lower by approximately 20% and 52%, respectively. Under SEC reserve reporting rules, prices are based on the historical 12-month average price based on closing prices on the first day of each month. We expect that additional periods of depressed commodity prices would continue to adversely affect our SEC-mandated prices, as higher 2014 prices would be replaced by lower 2015 prices in the computation of the 12-month average, resulting in further reductions of our estimated proved reserve volumes and estimated future net revenues. Accordingly, we expect to incur additional write-downs of our oil and gas properties in future periods should lower prices persist. Additionally, continued low commodity prices, further declines in commodity prices and/or widening negative price differentials (particularly in Appalachia) will likely have a material adverse impact on future cash flows, and could substantially reduce the available borrowings under our bank credit facility and constrain our capital budgets beyond 2015.

We are subject to evaluations by the Bureau of Ocean Energy Management for continuation of our current exemption from supplemental bonding on abandonment obligations. It is possible that future agency action or failure to meet the required levels of compliance as a result of declining commodity prices could result in a loss of exemption and could have a material adverse impact on our liquidity should we be required to post bonds or letters of credit.

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.

Liquidity and Capital Resources

As of August 5, 2015, we had cash on hand of approximately $90 million and $480.8 million of availability under our bank credit facility. The decline in commodity prices has adversely impacted the value of our estimated proved reserves and could result in a reduction of our borrowing base at the next redetermination, which is expected in October 2015. 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 expenditures with cash flows from operating activities and cash on hand. However, if we are unable to successfully execute planned sales of minority working interests or defer certain expenditures, or if we experience continued low commodity prices or other factors, a portion of our 2015 capital expenditures will likely 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. Our ability to access the public or private markets on economic terms will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.

Cash Flows and Working Capital. Net cash provided by operating activities totaled $145.7 million during the six months ended June 30, 2015 compared to $257.0 million during the comparable period in 2014.

Net cash used in investing activities totaled $75.5 million during the six months ended June 30, 2015, which primarily represents our investment in oil and gas properties of $264.4 million, offset by $179.5 million of previously restricted proceeds from the sale of oil and gas properties and $10.1 million of proceeds from the sale of oil and gas properties. Net cash used in investing activities totaled $470.2 million during the six months ended June 30, 2014, which primarily represents our investment in oil and gas properties of $517.9 million, offset by proceeds from the sale of oil and gas properties of $52.0 million.

Net cash used in financing activities totaled $3.1 million during the six months ended June 30, 2015, which primarily represents net payments for share-based compensation. During the six months ended June 30, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $215.9 million during the six months ended June 30, 2014, which primarily represents net proceeds from the sale of common stock of approximately $226.0 million, offset by net payments for share-based compensation of approximately $6.9 million and deferred financing costs of approximately $3.2 million associated with our credit facility.

 

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We had working capital at June 30, 2015 of $93.0 million.

Capital Expenditures. During the three months ended June 30, 2015, additions to oil and gas property costs of $113.7 million included $2.0 million of lease and property acquisition costs, $7.4 million of capitalized SG&A expenses (inclusive of incentive compensation) and $10.8 million of capitalized interest. During the six months ended June 30, 2015, additions to oil and gas property costs of $219.4 million included $1.3 million of lease and property acquisition costs, $15.9 million of capitalized SG&A expenses (inclusive of incentive compensation) and $21.6 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. The next redetermination of our borrowing base under the bank credit facility is expected in October 2015. Continued low commodity prices, further declines in commodity prices and/or widening negative price differentials (particularly in Appalachia) will likely have a material adverse impact on the value of our estimated proved reserves and could result in a reduction of our borrowing base. As of June 30 and August 5, 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 our Guarantor 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 June 30, 2015, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.78 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 9.20 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 June 30, 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 six months ended June 30, 2015.

 

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Results of Operations

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

 

		Three Months Ended June 30,
		2015				2014				Variance				% Change
Production:
Oil (MBbls)			1,534				1,481				53				4	%
Natural gas (MMcf)			12,581				12,363				218				2	%
NGLs (MBbls)			794				467				327				70	%
Oil, natural gas and NGLs (MMcfe)			26,549				24,051				2,498				10	%
Revenue data (in thousands): (1)
Oil revenue		$	111,585			$	142,393			($	30,808	)			(22	%)
Natural gas revenue			26,907				46,667				(19,760	)			(42	%)
NGLs revenue			11,033				15,936				(4,903	)			(31	%)
Total oil, natural gas and NGL revenue		$	149,525			$	204,996			($	55,471	)			(27	%)
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)		$	55.55			$	100.30			($	44.75	)			(45	%)
Natural gas (per Mcf)			1.82				4.03				(2.21	)			(55	%)
NGLs (per Bbl)			13.90				34.12				(20.22	)			(59	%)
Oil, natural gas and NGLs (per Mcfe)			4.49				8.91				(4.42	)			(50	%)
Including the cash settlement of effective hedging contracts
Oil (per Bbl)		$	72.74			$	96.15			($	23.41	)			(24	%)
Natural gas (per Mcf)			2.14				3.77				(1.63	)			(43	%)
NGLs (per Bbl)			13.90				34.12				(20.22	)			(59	%)
Oil, natural gas and NGLs (per Mcfe)			5.63				8.52				(2.89	)			(34	%)
Expenses (per Mcfe):
Lease operating expenses		$	1.03			$	2.06			($	1.03	)			(50	%)
Transportation, processing and gathering expenses			0.75				0.59				0.16				27	%
SG&A expenses (2)			0.62				0.69				(0.07	)			(10	%)
DD&A expense on oil and gas properties			2.89				3.82				(0.93	)			(24	%)

 

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

(2)	Excludes incentive compensation expense.

 

		Six Months Ended June 30,
		2015				2014				Variance				% Change
Production:
Oil (MBbls)			3,156				2,899				257				9	%
Natural gas (MMcf)			23,738				25,004				(1,266	)			(5	%)
NGLs (MBbls)			1,477				977				500				51	%
Oil, natural gas and NGLs (MMcfe)			51,536				48,260				3,276				7	%
Revenue data (in thousands): (1)
Oil revenue		$	219,092			$	280,682			($	61,590	)			(22	%)
Natural gas revenue			55,244				103,029				(47,785	)			(46	%)
NGLs revenue			23,399				43,906				(20,507	)			(47	%)
Total oil, natural gas and NGL revenue		$	297,735			$	427,617			($	129,882	)			(30	%)
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)		$	50.28			$	99.80			($	49.52	)			(50	%)
Natural gas (per Mcf)			2.04				4.43				(2.39	)			(54	%)
NGLs (per Bbl)			15.84				44.94				(29.10	)			(65	%)
Oil, natural gas and NGLs (per Mcfe)			4.47				9.20				(4.73	)			(51	%)
Including the cash settlement of effective hedging contracts
Oil (per Bbl)		$	69.42			$	96.82			($	27.40	)			(28	%)
Natural gas (per Mcf)			2.33				4.12				(1.79	)			(43	%)
NGLs (per Bbl)			15.84				44.94				(29.10	)			(65	%)
Oil, natural gas and NGLs (per Mcfe)			5.78				8.86				(3.08	)			(35	%)

 

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		Six Months Ended June 30,
		2015				2014				Variance				% Change
Expenses (per Mcfe):
Lease operating expenses		$	1.07			$	2.00			($	0.93	)			(47	%)
Transportation, processing and gathering expenses			0.73				0.60				0.13				22	%
SG&A expenses (2)			0.65				0.68				(0.03	)			(4	%)
DD&A expense on oil and gas properties			3.14				3.60				(0.46	)			(13	%)

 

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

(2)	Excludes incentive compensation expense.

Net Income. During the three months ended June 30, 2015, we reported a net loss totaling approximately $152.9 million, or $2.77 per share, compared to net income for the three months ended June 30, 2014 of $4.4 million, or $0.08 per share. During the six months ended June 30, 2015, we reported a net loss totaling approximately $480.3 million, or $8.70 per share, compared to net income for the six months ended June 30, 2014 of $30.4 million, or $0.59 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 June 30, 2015, we recognized ceiling test write-downs of our U.S. and Canadian oil and gas properties totaling $224.3 million ($143.5 million after taxes). 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-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.

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

Production. During the three months ended June 30, 2015, total production volumes increased to 26.5 Bcfe compared to 24.1 Bcfe produced during the comparable 2014 period, representing a 10% increase. Oil production during the three months ended June 30, 2015 totaled approximately 1,534,000 Bbls compared to 1,481,000 Bbls produced during the comparable 2014 period. Natural gas production totaled 12.6 Bcf during the three months ended June 30, 2015 compared to 12.4 Bcf during the comparable 2014 period. NGL production during the three months ended June 30, 2015 totaled approximately 794,000 Bbls compared to 467,000 Bbls produced during the comparable 2014 period.

During the six months ended June 30, 2015, total production volumes increased to 51.5 Bcfe compared to 48.3 Bcfe produced during the comparable 2014 period, representing a 7% increase. Oil production during the six months ended June 30, 2015 totaled approximately 3,156,000 Bbls compared to 2,899,000 Bbls produced during the comparable 2014 period. Natural gas production totaled 23.7 Bcf during the six months ended June 30, 2015 compared to 25.0 Bcf during the comparable 2014 period. NGL production during the six months ended June 30, 2015 totaled approximately 1,477,000 Bbls compared to 977,000 Bbls produced during the comparable 2014 period.

During the three months ended June 30, 2015, we realized increases to our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units. Although we recognized approximately 1.7 Bcfe of incremental production volumes associated with increased interests, net operating income for the affected wells was only minimally impacted due to depressed commodity prices. The increase in oil volumes during the six months ended June 30, 2015 was also attributable to production from our deepwater Cardona wells, which began producing late in the fourth quarter of 2014. These increases in production volumes were partially offset by decreases in production resulting from the divestitures of certain of our non-core GOM conventional shelf properties during 2014. Additionally, production during the three months ended June 30, 2015 was negatively impacted by downtime at the Pompano platform for third-party pipeline maintenance.

Prices. Prices realized during the three months ended June 30, 2015 averaged $72.74 per Bbl of oil, $2.14 per Mcf of natural gas and $13.90 per Bbl of NGLs, or 34% lower, on an Mcfe basis, than average realized prices of $96.15 per Bbl of oil, $3.77 per Mcf of natural gas and $34.12 per Bbl of NGLs during the comparable 2014 period. Prices realized during the six months ended June 30, 2015 averaged $69.42 per Bbl of oil, $2.33 per Mcf of natural gas and $15.84 per Bbl of NGLs, or 35% lower, on an Mcfe basis, than average realized prices of $96.82 per Bbl of oil, $4.12 per Mcf of natural gas and $44.94 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 $0.32 per Mcf and increased our average realized oil price by $17.19 per Bbl during the three months ended June 30, 2015. During the three months ended June 30, 2014, our effective hedging transactions decreased our average realized natural gas price by $0.26 per Mcf and decreased our average realized oil price by $4.15 per Bbl. During the six months eneded June 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.29 per Mcf and increased our average realized oil price by $19.14 per Bbl. During the six months ended June 30, 2014, our effective hedging transactions decreased our average realized natural gas price by $0.31 per Mcf and decreased our average realized oil price by $2.98 per Bbl.

 

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Revenue. Oil, natural gas and NGL revenue was $149.5 million during the three months ended June 30, 2015 compared to $205.0 million during the comparable period of 2014. For the six months ended June 30, 2015 and 2014, oil, natural gas and NGL revenue totaled $297.7 million and $427.6 million, respectively. The decrease in total revenue for the three and six months ended June 30, 2015 was primarily due to a 34% and 35% decrease, respectively, in average realized prices from the comparable periods of 2014. The decreases were also attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014.

Derivative Income/Expense. Net derivative expense for the three months ended June 30, 2015 totaled $0.7 million, comprised of $5.7 million of income from cash settlements and $6.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended June 30, 2014, net derivative expense totaled $2.5 million, comprised of $0.3 million of expense from cash settlements and $2.2 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. Net derivative income for the six months ended June 30, 2015 totaled $2.4 million, comprised of $10.3 million of income from cash settlements and $7.9 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the six months ended June 30, 2014, net derivative expense totaled $3.1 million, comprised of $0.4 million of expense from cash settlements and $2.7 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 June 30, 2015 and 2014 totaled $27.4 million and $49.5 million, respectively. For the six months ended June 30, 2015 and 2014, lease operating expenses totaled $55.0 million and $96.4 million, respectively. On a unit of production basis, lease operating expenses were $1.03 per Mcfe and $2.06 per Mcfe for the three months ended June 30, 2015 and 2014, respectively, and $1.07 per Mcfe and $2.00 per Mcfe for the six months ended June 30, 2015 and 2014, respectively. The decrease in lease operating expenses during the three and six months ended June 30, 2015 was primarily attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014 as well as service cost reductions.

Transportation, processing and gathering expenses during the three months ended June 30, 2015 and 2014 totaled $19.9 million and $14.1 million, respectively, or $0.75 per Mcfe and $0.59 per Mcfe, respectively. For the six months ended June 30, 2015 and 2014, transportation, processing and gathering expenses totaled $37.6 million and $28.7 million, respectively, or $0.73 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 June 30, 2015 totaled $76.8 million compared to $91.9 million during the comparable period of 2014. For the six months ended June 30, 2015 and 2014, DD&A expense totaled $162.0 million and $173.7 million, respectively. On a unit of production basis, DD&A expense was $2.89 per Mcfe and $3.82 per Mcfe during the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, DD&A expense, on a unit of production basis, was $3.14 per Mcfe and $3.60 per Mcfe, respectively.

SG&A expenses (exclusive of incentive compensation) for the three months ended June 30, 2015 were $16.4 million compared to $16.6 million for the three months ended June 30, 2014. For the six months ended June 30, 2015 and 2014, SG&A expenses (exclusive of incentive compensation) totaled $33.4 million and $33.0 million, respectively. On a unit of production basis, SG&A expenses were $0.62 per Mcfe and $0.69 per Mcfe for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, SG&A expenses, on a unit of production basis, were $0.65 per Mcfe and $0.68 per Mcfe, respectively.

For the three months ended June 30, 2015 and 2014, incentive compensation expense totaled $1.3 million and $3.9 million, respectively. For the six months ended June 30, 2015 and 2014, incentive compensation expense totaled $2.8 million and $7.0 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 June 30, 2015 totaled $10.5 million, net of $10.8 million of capitalized interest, compared to interest expense of $9.9 million, net of $11.3 million of capitalized interest, during the comparable 2014 period. For the six months ended June 30, 2015, interest expense totaled $20.8 million, net of $21.6 million of capitalized interest, compared to interest expense of $18.3 million, net of $24.1 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 six months ended June 30, 2015 and 2014, we recorded an income tax (benefit) provision of ($265.0) million and $18.1 million, respectively. The income tax benefit recorded for the six months ended June 30, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs.

 

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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 six months ended June 30, 2015, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $6.7 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we 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 47% of our estimated 2015 production from estimated proved reserves and 12% of our estimated 2016 production from estimated proved reserves. Although we continue to monitor the marketplace for additional hedges for 2016 and beyond, continued weakness in commodity prices may impair our ability to secure hedges at prices we deem acceptable. See Part I, Item 1. Financial Statements – Note 3 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 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 June 30, 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 June 30, 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

 

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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 June 30, 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 June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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 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. All four cases have been remanded to Louisiana 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. During the three months ended June 30, 2015, Stone and Kimmeridge settled both claims for an amount within the previously disclosed range of loss (between $0 and $2,118,878).

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 such 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. Stone settled the enforcements action for the Conley and Tuttle Impoundment Sites for $135,647 and $141,245, respectively. The EPA has also approved Stone’s wetland and stream delineation report. Final settlement is subject to the execution of the applicable consent orders, which already have been negotiated. Stone is still required to submit its restoration plan for both sites, and upon approval by the EPA, complete restoration.

 

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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 June 30, 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
April 1 – April 30, 2015			—			$	—				—
May 1 – May 31, 2015			5,538				14.11				—
June 1 – June 30, 2015			—				—				—
			5,538			$	14.11				—			$	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 June 30, 2015.

 

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Item 6. Exhibits

 

*3.1		Certificate of Incorporation of the Registrant, as amended.
3.2		Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 filed February 27, 2014 (File No. 001-12074)).
*10.1		Amendment No. 1 to Credit Agreement, dated as of May 1, 2015, among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions party to the Fourth Amended and Restated Credit Agreement.
*10.2		First Supplemental Indenture and Guarantee, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore LLC and The Bank of New York Mellon Trust Company, N.A., as trustee.
*10.3		Fourth Supplemental Indenture, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore LLC and The Bank of New York Mellon Trust Company, N.A. as trustee.
10.4		Second Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix B to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2015 Annual Meeting of Stockholders (File No. 001-12074)).
10.5		Third Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix B to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2015 Annual Meeting of Stockholders (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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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: August 6, 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)

 

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EXHIBIT INDEX

 

Exhibit Number		Description
*3.1		Certificate of Incorporation of the Registrant, as amended.
3.2		Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 filed February 27, 2014 (File No. 001-12074)).
*10.1		Amendment No. 1 to Credit Agreement, dated as of May 1, 2015, among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions party to the Fourth Amended and Restated Credit Agreement.
*10.2		First Supplemental Indenture and Guarantee, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore LLC and The Bank of New York Mellon Trust Company, N.A., as trustee.
*10.3		Fourth Supplemental Indenture, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore LLC and The Bank of New York Mellon Trust Company, N.A. as trustee.
10.4		Second Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix B to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2015 Annual Meeting of Stockholders (File No. 001-12074)).
10.5		Third Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix B to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2015 Annual Meeting of Stockholders (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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