Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - FORM 8-K - Energy XXI Ltd	v386945_8k.htm
EX-23.1 - EXHIBIT 23.1 - Energy XXI Ltd	v386945_ex23-1.htm
EX-99.2 - EXHIBIT 99.1 - Energy XXI Ltd	v386945_ex99-2.htm

EXHIBIT 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of EPL Oil & Gas, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of EPL Oil & Gas, Inc. and its subsidiaries (the “Company”) at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

February 27, 2014

EPL OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2013, 2012
(In thousands, except per share data)

	December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	8,812		$	1,521
Trade accounts receivable – net		70,707			67,991
Fair value of commodity derivative instruments		501			3,302
Deferred tax asset		8,949			3,322
Prepaid expenses		6,868			9,873
Total current assets		95,837			86,009
Property and equipment, at cost under the successful efforts method of accounting		2,355,219			2,025,647
Less accumulated depreciation, depletion, amortization and impairments		(618,788	)		(427,580	)
Net property and equipment		1,736,431			1,598,067
Deposit for Nexen Acquisition		7,040			—
Restricted cash		6,023			6,023
Fair value of commodity derivative instruments		238			211
Deferred financing costs - net of accumulated amortization of $5,549 and $2,596 at December 31, 2013 and 2012, respectively		10,106			12,386
Other assets		2,156			2,931
Total assets	$	1,857,831		$	1,705,627
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	59,431		$	34,772
Accrued expenses		131,125			117,372
Asset retirement obligations		51,601			30,179
Fair value of commodity derivative instruments		29,636			10,026
Total current liabilities		271,793			192,349
Long-term debt		627,355			689,911
Asset retirement obligations		203,849			204,931
Deferred tax liabilities		122,812			67,694
Fair value of commodity derivative instruments		2,136			3,637
Other		673			1,132
Total liabilities		1,228,618			1,159,654
Commitments and contingencies (Note 13)
Stockholders’ equity:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at December 31, 2013 and 2012		—			—
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; shares issued: 40,970,137 and 40,601,887 at December 31, 2013 and 2012, respectively; shares outstanding: 39,097,394 and 39,103,203 at December 31, 2013 and 2012, respectively		41			40
Additional paid-in capital		519,114			510,469
Treasury stock, at cost, 1,872,743 and 1,498,684 shares at December 31, 2013 and 2012, respectively		(31,157	)		(20,477	)
Retained earnings		141,215			55,941
Total stockholders’ equity		629,213			545,973
Total liabilities and stockholders' equity	$	1,857,831		$	1,705,627

See accompanying notes to consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2013, 2012 and 2011
(In thousands, except per share data)

	Year Ended December 31,
	2013			2012			2011
Revenue:
Oil and natural gas	$	688,743		$	422,529		$	348,207
Other		4,295			1,104			120
Total revenue		693,038			423,633			348,327
Costs and expenses:
Lease operating		165,841			94,850			70,281
Transportation		3,568			615			779
Exploration expenditures and dry hole costs		26,555			18,799			14,268
Impairments		2,937			8,883			32,466
Depreciation, depletion and amortization		200,359			113,581			104,624
Accretion of liability for asset retirement obligations		28,299			15,565			15,942
General and administrative		28,137			23,208			18,741
Taxes, other than on earnings		11,490			13,007			14,365
Gain on sales of assets		(28,681	)		-			-
Other		34,942			4,678			9,735
Total costs and expenses		473,447			293,186			281,201
Income from operations		219,591			130,447			67,126
Other income (expense):
Interest income		99			136			102
Interest expense		(52,368	)		(28,568	)		(17,548	)
Loss on derivative instruments		(32,361	)		(13,305	)		(5,870	)
Loss on early extinguishment of debt		-			-			(2,377	)
Total other expense		(84,630	)		(41,737	)		(25,693	)
Income before income taxes		134,961			88,710			41,433
Deferred income tax expense		(49,687	)		(29,900	)		(14,822	)
Net income		85,274			58,810			26,611
Basic earnings per share	$	2.18		$	1.50		$	0.66
Diluted earnings per share	$	2.15		$	1.50		$	0.66
Weighted average common shares used in computing earnings per share:
Basic		38,730			38,885			39,946
Diluted		39,236			39,034			40,050

See accompanying notes to consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(In thousands)

	Treasury Stock Shares		Treasury Stock			Common Stock Shares		Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Total
Balance, December 31, 2010		—	$	—			40,092	$	40	$	502,556		$	(29,480	)	$	473,116
Net income		—		—			—		—		—			26,611			26,611
Stock options and restricted share awards		—		—			217		—		2,509			—			2,509
Exercise of stock options		—		—			13		—		119			—			119
Purchase of shares into treasury		916		(11,353	)		—		—		—			—			(11,353	)
Restricted stock used for tax withholdings		6		(8	)		—		—		—			—			(8	)
Other		—		—			4		—		51			—			51
Balance, December 31, 2011		922	$	(11,361	)		40,326	$	40	$	505,235		$	(2,869	)	$	491,045
Net income		—		—			—		—		—			58,810			58,810
Stock options and restricted share awards		—		—			226		—		4,717			—			4,717
Exercise of stock options		—		—			48		—		441			—			441
Purchase of shares into treasury		549		(8,798	)		—		—		—			—			(8,798	)
Restricted stock used for tax withholdings		28		(318	)		—		—		—			—			(318	)
Other		—		—			2		—		76			—			76
Balance, December 31, 2012		1,499	$	(20,477	)		40,602	$	40	$	510,469		$	55,941		$	545,973
Net income		—		—			—		—		—			85,274			85,274
Stock options and restricted share awards		2		—			258		—		7,344			—			7,344
Exercise of stock options		—		—			108		1		1,384			—			1,385
Purchase of shares into treasury		334		(9,640	)		—		—		—			—			(9,640	)
Restricted stock used for tax withholdings		38		(1,040	)		—		—		—			—			(1,040	)
Other		—		—			2		—		(83	)		—			(83	)
Balance, December 31, 2013		1,873	$	(31,157	)		40,970	$	41	$	519,114		$	141,215		$	629,213

See accompanying notes to consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(In thousands)

	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	85,274		$	58,810		$	26,611
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		200,359			113,581			104,624
Accretion of liability for asset retirement obligations		28,299			15,565			15,942
Change in fair value of derivative instruments		20,884			9,491			(11,475	)
Non-cash compensation		7,344			4,717			2,509
Deferred income taxes		49,687			29,900			14,822
Exploration expenditures		5,520			4,227			11,239
Impairments		2,937			8,883			32,466
Amortization of deferred financing costs and discount on debt		5,396			2,556			1,657
Gain on sales of assets		(28,681	)		—			—
Loss on early extinguishment of debt		—			—			2,377
Other		27,235			2,448			6,984
Changes in operating assets and liabilities:
Trade accounts receivable		(1,916	)		(33,547	)		(10,037	)
Other receivables		—			—			2,088
Prepaid expenses		2,081			1,047			(7,623	)
Other assets		790			145			(1,215	)
Accounts payable and accrued expenses		35,658			31,477			12,650
Asset retirement obligation settlements		(53,308	)		(35,429	)		(32,364	)
Other liabilities		—			—			(3	)
Net cash provided by operating activities		387,559			213,871			171,252
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		—			—			2,466
Property acquisitions		(27,560	)		(578,372	)		(235,486	)
Deposit for Nexen Acquisition		(7,040	)		—			—
Exploration and development expenditures		(322,040	)		(184,850	)		(76,003	)
Other property and equipment additions		(2,016	)		(1,743	)		(1,568	)
Proceeds from sale of assets		52,317			—			—
Net cash used in investing activities		(306,339	)		(764,965	)		(310,591	)
Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		—			509,313			203,794
Repayments of indebtedness		(65,000	)		(20,000	)		—
Deferred financing costs		(674	)		(8,469	)		(6,646	)
Purchase of shares into treasury		(9,640	)		(8,798	)		(11,353	)
Exercise of stock options		1,385			441			119
Net cash provided by (used in) financing activities		(73,929	)		472,487			185,914
Net increase (decrease) in cash and cash equivalents		7,291			(78,607	)		46,575
Cash and cash equivalents at beginning of period		1,521			80,128			33,553
Cash and cash equivalents at end of period	$	8,812		$	1,521		$	80,128
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest		47,339			21,129			9,395

See accompanying notes to consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

Organization and Summary of Significant Accounting Policies

EPL Oil & Gas, Inc. (“we,” “our,” “us,” or “the Company”) was incorporated as a Delaware corporation on January 29, 1998. We are an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana. Effective September 1, 2012, we changed our legal corporate name from “Energy Partners, Ltd.” to “EPL Oil & Gas, Inc.” through a short-form merger pursuant to Section 253 of the General Corporation Law of the State of Delaware.

Recent Events. On January 15, 2014, we acquired 100% working interest of certain shallow-water central Gulf of Mexico shelf oil and natural gas assets comprised of five leases in the Eugene Island 258/259 field for $70.4 million, subject to customary adjustments to reflect the September 1, 2013, economic effective date. This acquisition was financed with borrowings under our Senior Credit Facility. In January 2014, we requested and received, with the approval of our lenders, a $50.0 million increase in our borrowing base bringing our borrowing base under the Senior Credit Facility to $475.0 million. See Note 7, “Indebtedness” for more information regarding our Senior Credit Facility.

A summary of acquisition activity during 2013, 2012 and 2011 is as follows (purchase prices are before economic effective date adjustments):

On September 26, 2013, we acquired an asset package consisting of certain Gulf of Mexico shelf oil and natural gas interests in the West Delta 29 field for $21.8 million;

On October 31, 2012, we acquired from Hilcorp Energy GOM Holdings, LLC 100% of the membership interests of Hilcorp Energy GOM, LLC, which owned certain shallow water Gulf of Mexico shelf oil and natural gas interests for $550.0 million;

On May 15, 2012, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests in our South Timbalier 41 field located in the Gulf of Mexico for $32.4 million;

On November 17, 2011, we acquired interests in the Main Pass 296/311 complex along with other unit interests in the Main Pass complex and an interest in a Main Pass 295 primary term lease for $38.6 million; and

In addition, on April 2, 2013, we sold certain shallow water Gulf of Mexico shelf oil and natural gas interests located within the non-operated Bay Marchand field for total consideration of $62.8 million. See Note 2, “Acquisitions and Disposition” for more information regarding these transactions.

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

(a) Basis of Presentation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of EPL Oil & Gas, Inc. and our wholly-owned subsidiaries. All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

(b) Property and Equipment

We use the successful efforts method of accounting for oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. We may capitalize exploratory well costs beyond one year if (a) we found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project; otherwise, these costs are expensed. Geological and geophysical costs are charged to expense as incurred.

Leasehold acquisition costs are capitalized as unproved properties. If proved reserves are found on undeveloped leases, the related leasehold costs are transferred to proved properties and amortized using the units of production method. For individual unevaluated properties with capitalized costs below a threshold amount, we allocate capitalized costs to earnings generally over the primary lease terms. Properties that are subject to amortization and those with capitalized costs greater than the threshold amount are assessed for impairment periodically. Capitalized costs of producing oil and natural gas properties are depreciated and depleted by the units-of-production method.

We evaluate our capitalized costs of proved oil and natural gas properties for potential impairment when circumstances indicate that the carrying values may not be recoverable. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserve volumes, actual operating and development costs in excess of expected amounts, changes in estimates of future operating and capital expenditure requirements, or other changes to contracts, environmental regulations or tax laws. The calculation is performed on a field-by-field basis, utilizing our current estimates of future revenues and operating expenses. In the event net undiscounted cash flow is less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, along with the related asset retirement obligations, unless retained by us, and the resulting gain or loss is recognized in earnings.

We record our obligations associated with the retirement of tangible long-lived assets at their fair values in the period incurred. The fair value of the obligation is also recorded to the related asset’s carrying amount. Accretion of the liability is recognized as an operating expense and the capitalized cost is amortized using the units-of-production method. We revise our estimates of asset retirement obligations as information about material changes to the liability becomes known. Revisions are recorded as adjustments to existing liabilities and to the carrying amount of the related assets. Revisions occurring at or near the end of an asset’s useful life may result in impairments or losses and could materially impact earnings. Our asset retirement obligations relate primarily to the plugging and abandonment of our oil and natural gas wellbores and to decommissioning related pipelines, facilities and structures.

(d) Income Taxes

We account for income taxes under the asset and liability method, which requires that we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. We recognize the effect on deferred tax assets and liabilities of a change in the tax rates in income in the period that includes the enactment date.

We follow the provisions of Accounting Standards Codification (“ASC”) Topic 740, “Income Taxes,” which apply to the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These provisions also contain guidance on de-recognition, classification, interest and penalties. Interest, if any, is classified as a component of interest expense, and statutory penalties, if any, are classified as a component of general and administrative expense.

(e) Deferred Financing Costs

We defer costs incurred to obtain debt financing and then amortize such costs as additional interest expense over the maturity period of the related debt using the effective interest rate method.

(f) Earnings Per Share

Basic earnings per share is computed by dividing income or loss available to common stockholders by the weighted average number of common shares outstanding during each period. According to GAAP, we have determined that our unvested restricted share awards, which contain non-forfeitable rights to dividends, are participating securities and should be included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between common shares and participating securities. The diluted earnings per share calculation under the “two-class” method also includes the effect, if dilutive, of potential common shares associated with stock option awards outstanding during each period. The dilutive effect of stock options is determined using the treasury stock method.

(g) Revenue Recognition

We record revenues from the sales of oil and natural gas when the product is delivered at a determinable price, title has transferred and collectability is reasonably assured. When we have an interest with other producers in properties from which natural gas is produced, we use the entitlement method for recording natural gas sales revenue. Under this method of accounting, revenue is recorded based on our net revenue interest in production. Deliveries of natural gas in excess of our revenue interest are recorded as liabilities and under-deliveries are recorded as receivables. We had natural gas imbalance liabilities of $2.0 million and $1.7 million at December 31, 2013 and 2012, respectively. We had natural gas imbalance receivables of $1.9 million and $0.8 million at December 31, 2013 and 2012, respectively.

(h) Cash and Cash Equivalents

We include in cash and cash equivalents our highly-liquid investments with original maturities of three months or less. At December 31, 2013 and 2012, cash and cash equivalents includes investments in overnight interest-bearing deposits of $7.3 million and $2.3 million, respectively. These amounts are reduced by overdraft balances on other operating accounts with legal right of offset in the same banking institution to arrive at the cash and cash equivalent balances reported in our consolidated balance sheets.

(i) Derivative Activities

Derivative instruments, including certain derivative instruments embedded in other contracts, are recorded at fair value and included as either assets or liabilities in the balance sheet. The accounting for changes in fair value depends on the intended use of the derivative and the resulting designation, which is established at the inception of the derivative. We do not elect to designate derivative instruments as hedges. Gains and losses resulting from changes in the fair value of derivative instruments are recorded in other income (expense). Gains and losses related to contract settlements are also recorded in other income (expense).

(j) Share-Based Compensation

We recognize share-based compensation expense based on the estimated grant-date fair value of all share-based awards, net of an estimated forfeiture rate, over the requisite service period of the awards, which is generally equivalent to the vesting term. We record share-based compensation expense only for those awards expected to vest. We periodically revise our estimated forfeiture rate if actual forfeitures differ from our estimates.

We are required to report excess tax benefits from the exercise of stock options as financing cash flows. For the year ended December 31, 2013 and 2012, no excess tax benefits were reported in the statement of cash flows as we were in a net operating loss carryforward position. See Note 12 for additional disclosures.

(k) Allowance for Doubtful Accounts

We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Our crude oil and natural gas revenue receivables are typically collected within two months. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest receivables on properties where we are the operator. When we believe collection of the full amount of our accounts receivable is in doubt, we record an allowance to reflect accounts receivable at the net realizable value, which may be reflected in earnings or as an increase to the net book value of our oil and natural gas properties depending on the nature of the transaction that created the receivable. The nature of the transaction resulting in the receivable balance determines whether the allowance, when recorded, impacts our earnings (ordinarily through LOE) or our property and equipment balances. As of December 31, 2013, our allowance for doubtful accounts was $0.7 million, $0.1 million of which was recorded as a recovery in earnings in 2013. As of December 31, 2012, our allowance for doubtful accounts was $0.7 million, $0.1 million of which was recorded as a recovery in earnings in 2012.

(l) Accrued Expenses

As of December 31, 2013, our accrued expenses included accrued exploration costs, development costs and lease operating expenses totaling approximately $107.8 million, other accrued expenses of $7.5 million and interest payable of approximately $15.8 million. As of December 31, 2012, our accrued expenses included accrued exploration costs, development costs and lease operating expenses totaling approximately $84.9 million, other accrued expenses of $16.3 million and interest payable of approximately $16.2 million.

(m) Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We use historical experience and various other assumptions that are believed to be reasonable under the circumstances to form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates and assumptions used in preparation of our financial statements. Significant estimates with regard to these financial statements and related unaudited disclosures include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows therefrom disclosed in Note 15.

(n) New Accounting Pronouncements

Effective January 1, 2013, we adopted the amended disclosure requirements contained in ASU 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This guidance impacted the disclosures associated with our derivative instruments and did not impact our consolidated financial position, results of operations or cash flows. See Note 7, “Fair Value Measurements,” of our consolidated financial statements in Part I, Item 1 of this Quarterly Report for related disclosures.

In July 2013, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” The amendments in this update clarify the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments are effective for fiscal years, and interim periods within those years, beginning December 15, 2013. We do not expect this guidance to have a material impact on our consolidated financial position, results of operations or cash flows.

(2) Acquisitions and Dispositions

Sale of Non-Operated Bay March and Asset

On April 2, 2013, we sold certain shallow water Gulf of Mexico shelf oil and natural gas interests located within the non-operated Bay Marchand field (the “BM Interests”) to the property operator for $51.5 million in cash and the buyer’s assumption of liabilities recorded on our balance sheet of $11.3 million resulting in total consideration of $62.8 million, subject to customary adjustments to reflect the January 1, 2013 economic effective date. Our results for the year ended December 31, 2013 reflect a pre-tax gain of $28.1 million from this sale. The following table summarizes the carrying amount of the net assets sold and reflects management’s estimates of customary adjustments to the sale price of approximately $0.7 million to reflect the economic effective date of January 1, 2013.

(In thousands)	January 1, 2013
Oil and natural gas properties	$	35,298
Asset retirement obligations		(3,959	)
Other liabilities		(7,311	)
Net assets sold	$	24,028

The cash proceeds from this sale of assets were held on deposit with a qualified intermediary in contemplation of a potential tax-deferred exchange of properties and classified as restricted cash at June 30, 2013. On September 26, 2013, we used $16.5 million of these proceeds to fund the WD29 Acquisition (defined and described below), which was a qualifying purchase for tax-deferral purposes. On September 29, 2013, the underlying escrow agreement expired, and the remaining amount of the deposit became unrestricted.

The West Delta 29 Acquisition

On September 26, 2013, we acquired from W&T Offshore, Inc. (“W&T”) an asset package consisting of certain Gulf of Mexico shelf oil and natural gas interests in the West Delta 29 field (the “WD29 Interests”) for $21.8 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2013 (the “WD29 Acquisition”). We estimate that the proved reserves as of the January 1, 2013 economic effective date totaled approximately 0.7 Mmboe, of which 95% were oil and 58% were proved developed reserves. The WD29 Acquisition was funded with a portion of the proceeds from the sale of the BM Interests held by the qualified intermediary as described above.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects management’s estimate of customary adjustments to purchase price provided for by the purchase and sale agreement of approximately $7.1 million to reflect an economic effective date of January 1, 2013.

(In thousands)	January 1, 2013
Oil and natural gas properties	$	16,696
Asset retirement obligations		(1,398	)
Net assets acquired	$	15,298

The Hilcorp Acquisition

On October 31, 2012, we acquired from Hilcorp Energy GOM Holdings, LLC (“Hilcorp”) 100% of the membership interests of Hilcorp Energy GOM, LLC (the “Hilcorp Acquisition”), which owned certain shallow water Gulf of Mexico shelf oil and natural gas interest (the “Hilcorp Properties”) for $550.0 million in cash, subject to customary adjustments to reflect an economic effective date of July 1, 2012. As of December 31, 2012, the Hilcorp Properties had estimated proved reserves of approximately 37.2 Mmboe, of which 49% were oil and 58% were proved developed reserves. The primary factors considered by management in acquiring the Hilcorp Properties include the belief that the Hilcorp Acquisition provides an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise on the Gulf of Mexico shelf. The Hilcorp Acquisition also provides us with access to infrastructure and extensive acreage, with significant exploitation and development potential.

The Hilcorp Acquisition was financed with cash on hand, the net proceeds from the sale of $300 million in aggregate principal amount of 8.25% senior notes due 2018 (the “2012 Senior Notes”) and borrowings under our expanded Senior Credit Facility. After deducting the initial purchasers’ discount, we realized net proceeds of $289.5 million. See Note 7, “Indebtedness,” for more information regarding our 2012 Senior Notes.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $5.7 million to reflect an economic effective date of July 1, 2012.

(In thousands)	July 1, 2012
Oil and natural gas properties	$	698,660
Asset retirement obligations		(150,959	)
Net assets acquired	$	547,701

During the quarter ended December 31, 2013, we completed the allocation of the Hilcorp Acquisition purchase price resulting in an increase in the acquired asset retirement obligation of $22.1 million. This change was due primarily to changes in the timing of expected cash flows for the related abandonment and decommissioning activities.

The South Timbalier Acquisition

On May 15, 2012, we acquired from W&T an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests in our South Timbalier 41 field (the “ST41 Interests”) located in the Gulf of Mexico for $32.4 million in cash, subject to customary adjustments to reflect an economic effective date of April 1, 2012. We estimate that the proved reserves as of the April 1, 2012 economic effective date totaled approximately 1.0 Mmboe, of which 51% were oil and 84% were proved developed reserves. Prior to the ST41 Acquisition, we owned a 60% working interest in these properties, and W&T owned a 40% working interest. As a result of the ST41 Acquisition, we have become the sole working interest owner of the South Timbalier 41 field. We funded the ST41 Acquisition with cash on hand.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $0.4 million to reflect an economic effective date of April 1, 2012.

(In thousands)	April 1, 2012
Oil and natural gas properties	$	33,206
Asset retirement obligations		(1,878	)
Net assets acquired	$	31,328

The ASOP Acquisition

On February 14, 2011, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests surrounding the Mississippi River delta and a related gathering system (the “ASOP Properties”) from Anglo-Suisse Offshore Pipeline Partners, LLC (“ASOP”) for $200.7 million in cash, subject to purchase price adjustments to reflect an economic effective date of January 1, 2011. As of

December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. The primary factors considered by management in acquiring the ASOP Properties include the belief that the ASOP Acquisition provided an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise in the Gulf of Mexico shelf. We financed the ASOP Acquisition with the proceeds from the sale of $210.0 million in aggregate principal amount of the 2011 Senior Notes. After deducting the initial purchasers’ discount and offering expenses, we realized net proceeds of approximately $202.0 million. See Note 7, “Indebtedness” for more information regarding our 2011 Senior Notes.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $3.8 million to reflect an economic effective date of January 1, 2011.

(In thousands)	January 1, 2011
Oil and natural gas properties	$	221,751
Asset retirement obligations		(24,858	)
Net assets acquired	$	196,893

The Main Pass Acquisition

On November 17, 2011, we acquired certain interests in producing oil and natural gas assets in the shallow-water central Gulf of Mexico shelf (the “Main Pass Interests”) from Stone Energy Offshore, L.L.C. for $38.6 million in cash, subject to customary adjustments to reflect the economic effective date of November 1, 2011. The Main Pass Interests consist of additional interests in the Main Pass 296/311 complex that was included in the ASOP Acquisition, along with other unit interests in the Main Pass complex and an interest in a Main Pass 295 primary term lease. We estimate that the proved reserves as of the November 1, 2011 economic effective date totaled approximately 1.3 Mmboe, all of which were proved developed reserves and 96% of which were oil reserves. We funded the Main Pass Acquisition with cash on hand.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $0.7 million to reflect an economic effective date of November 1, 2011.

(In thousands)	November 1, 2011
Oil and natural gas properties	$	40,826
Asset retirement obligations		(2,991	)
Net assets acquired	$	37,835

We have accounted for our acquisitions using the purchase method of accounting for business combinations, and therefore we have estimated the fair value of the assets acquired and the liabilities assumed as of their respective acquisition dates. In the estimation of fair value, management uses various valuation methods including (i) comparable company analysis, which estimates the value of the acquired properties based on the implied valuations of other similar operations; (ii) comparable asset transaction analysis, which estimates the value of the acquired operations based upon publicly announced transactions of assets with similar characteristics; (iii) comparable merger transaction analysis, which, much like comparable asset transaction analysis, estimates the value of operations based upon publicly announced transactions with similar characteristics, except that merger analysis analyzes public to public merger transactions rather than solely asset transactions; and (iv) discounted cash flow analysis. The fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 10, “Fair Value Measurements.”

Results of Operations and Pro Forma Information

Revenues and lease operating expenses attributable to acquired interests and properties were as follows:

	Year Ended December 31,
	2013		2012		2011
	(In thousands)
WD29 Interests:
Revenues	$	3,011	$	—	$	—
Lease operating expenses	$	44	$	—	$	—
Hilcorp Properties:
Revenues	$	208,241	$	37,978	$	—
Lease operating expenses	$	74,404	$	10,982	$	—
ST41 Interests:
Revenues	$	11,189	$	9,262	$	—
Lease operating expenses	$	2,468	$	1,760	$	—
ASOP Properties and Main Pass Interests:
Revenues	$	328,070	$	175,538	$	125,975
Lease operating expenses	$	33,978	$	26,467	$	17,161

We have determined that the presentation of net income attributable to the acquired interests and properties is impracticable due to the integration of the related operations upon acquisition. We incurred fees of approximately $0.5 million related to the Hilcorp Acquisition and approximately $0.1 million related to the ST41 Acquisition, which were included in general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2012. We incurred fees of approximately $0.5 million related to the ASOP Acquisition and approximately $0.1 million related to the Main Pass Acquisition, which were included in general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2011.

The following supplemental pro forma information presents consolidated results of operations as if the Hilcorp Acquisition and the ST41 Acquisition had occurred on January 1, 2012. The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations, b) the statements of operations of Hilcorp Energy GOM, LLC, and c) the statements of revenues and direct operating expenses for the ST41 Interests, which were derived from our historical accounting records. This information does not purport to be indicative of results of operations that would have occurred had the acquisitions occurred on January 1, 2012, nor is such information indicative of any expected future results of operations.

	Year Ended December 31,
(in thousands, except per share data)	Pro Forma 2012
Revenue	$	594,510
Net income	$	59,324
Basic earnings per share	$	1.51
Diluted earnings per share	$	1.51

Subsequent Events

On January 15, 2014, we acquired from Nexen Petroleum Offshore U.S.A., Inc. (“Nexen”) 100% working interest of certain shallow-water central Gulf of Mexico shelf oil and natural gas assets for $70.4 million, subject to customary adjustments to reflect the September 1, 2013, economic effective date (the “Nexen Acquisition”). The assets we acquired comprise five leases in the Eugene Island 258/259 field (the “EI Interests”). Estimated proved reserves as of the September 1, 2013 effective date consist of approximately 2.6 Mmboe of proved developed producing reserves, about 91% of which is oil.

The Nexen Acquisition was financed with borrowings under our Senior Credit Facility. In January 2014, our lenders approved a $50.0 million increase in our borrowing base under our Senior Credit Facility, increasing our borrowing base to $475.0 million. See Note 7, “Indebtedness” for more information regarding our Senior Credit Facility.

The Nexen Acquisition will be accounted for using the purchase method of account for business combinations. The following allocation of the purchase price as of January 15, 2014, is preliminary and includes significant use of estimates. This preliminary allocation is based on information that was available to management at the time these consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas. Management has not yet had the opportunity to complete its assessment of the fair value of the assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by management, and the impact of such changes may be material.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects management’s estimate of customary adjustments of $3.6 million to reflect an economic effective date of September 1, 2013.

(In thousands)	September 1, 2013
Oil and natural gas properties	$	93,932
Asset retirement obligations		(27,133	)
Net assets acquired	$	66,799

Pro forma results of operations are not provided as the historical results of the EI Interests were not available at the time these consolidated financial statements were prepared.

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Common Stock

In August 2011, the Board of Directors authorized a program for the repurchase of our outstanding common stock for up to an aggregate cash purchase price of $20.0 million and increased the program to $40.0 million in May 2012. In July 2013, the Board of Directors increased the program to $80.0 million. Through December 31, 2013, we executed trades to repurchase 1,799,000 shares at an aggregate cash purchase price of approximately $29.7 million. Such shares are held in treasury and could be used to provide available shares for possible resale in future public or private offerings and our employee benefit plans. The repurchases have been, and will be, carried out in accordance with certain volume, timing and price constraints imposed by the Securities and Exchange Commission (the “SEC”) rules applicable to such transactions. The amount, timing and price of purchases otherwise depend on market conditions and other factors, including restrictions under our Senior Credit Facility. In July 2013, our Senior Credit Facility was amended to increase the limit applicable to certain restricted payments, which includes share repurchases, permitted by the agreement.

We have reserved up to 3,574,000 shares of common stock for the issuance of restricted shares and option shares under our 2009 Long-Term Incentive Plan, with 1,184,322 shares remaining for issuance as of December 31, 2013. In April 2013, the reserved shares were increased from 2,474,000 shares to 3,574,000. See Note 12, “Employee Benefit Plans” for information regarding the 2009 Long-Term Incentive Plan.

Covenants in certain debt instruments to which we are a party, including our Senior Credit Facility and the indenture related to our 8.25% Senior Notes, place certain restrictions and conditions on our ability to pay dividends on our common stock.

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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.

	Year Ended December 31,
	2013			2012			2011
	(in thousands, except per share data)
Income (numerator):
Net income	$	85,274		$	58,810		$	26,611
Net income attributable to participating securities		(943	)		(455	)		(77	)
Net income attributable to common shares	$	84,331		$	58,355		$	26,534
Weighted average shares (denominator):
Weighted average shares—basic		38,730			38,885			39,946
Dilutive effect of stock options		506			149			104
Weighted average shares—diluted		39,236			39,034			40,050
Basic earnings per share	$	2.18		$	1.50		$	0.66
Diluted earnings per share	$	2.15		$	1.50		$	0.66

The following table indicates the number of shares underlying outstanding stock-based awards excluded from the computation of dilutive weighted average shares because their effect was antidilutive for the periods indicated.

	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Weighted average shares		273		687		442

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Property and Equipment

The following table summarizes our property and equipment.

	December 31,
	2013		2012
	(In thousands)
Proved oil and natural gas properties	$	2,307,891	$	1,982,657
Unproved oil and natural gas properties		39,191		36,992
Other		8,137		5,998
Total property and equipment	$	2,355,219	$	2,025,647

Substantially all of our oil and natural gas properties serve as collateral under our credit facility.

We recognized impairments of $2.9 million, $8.9 million and $32.5 million in the years ended December 31, 2013, 2012 and 2011, respectively.

Impairments for the year ended December 31, 2013 were primarily related to reservoir performance at a gas well in one of our smaller producing fields. This field was determined to have future net cash flows less than its carrying value resulting in the write down of this property to its estimated fair value.

Impairments for the year ended December 31, 2012 were primarily due to the decline in our estimate of future natural gas prices affecting certain of our natural gas producing fields and to reservoir performance at two of those fields. These fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values. We also recorded impairments for undeveloped leases that are expiring in 2013 for which we had no development plans.

Impairments for the year ended December 31, 2011 were primarily related to our natural gas producing fields and our deepwater producing well (primarily natural gas). Impairments related to our deepwater producing well were primarily due to the decline in our estimate of future natural gas prices, reservoir performance and higher estimated operating costs. Additional impairments for the year ended December 31, 2011 were primarily related to reservoir performance at other natural gas producing fields.

At December 31, 2013 and 2012, we did not have any exploratory projects that were suspended for a period greater than one year.

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Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, along with a corresponding increase in the carrying amount of the related long-lived asset. The following table reconciles the beginning and ending aggregate recorded amount of our asset retirement obligations.

	Year Ended December 31,
	2013			2012
	(in thousands)
Beginning of period total	$	235,110		$	99,347
Accretion expense		28,299			15,565
Liabilities assumed in acquisitions		23,541			132,109
Liabilities incurred		1,187			1,210
Revisions		24,586			22,308
Liabilities associated with assets sold		(3,965	)		—
Liabilities settled		(53,308	)		(35,429	)
End of period total		255,450			235,110
Less: End of period, current portion		51,601			30,179
End of period, noncurrent portion	$	203,849		$	204,931

We revise our estimates of ARO as information about material changes to the liability becomes known. During the year ended December 31, 2013, our revisions include an increase to our estimated asset retirement obligations (“ARO”) of $20.8 million related to our only remaining four non-producing wellbores in our non-operated deepwater properties. These deepwater abandonment costs are primarily attributable to changes in regulatory interpretations and enforcement by the Bureau of Safety and Environmental Enforcement in the deepwater that increased the required scope of work. As a result, we recorded an associated $20.8 million loss on abandonment activities, which is included in Other costs and expenses in our consolidated statements of operations for the year ended December 31, 2013.

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Indebtedness

The following table sets forth our indebtedness.

	December 31,
	2013		2012
	(In thousands)
8.25% senior notes issued February 14, 2011 and October 25, 2012, face amount of $510.0 million,interest rate of 8.25% payable semi-annually, in arrears onFebruary 15 and August 15 of each year, maturity date February 15, 2018	$	497,355	$	494,911
Senior Credit Facility, interest rate based on base rate or LIBOR plus a floating spread, maturity date October 31, 2016		130,000		195,000
Total indebtedness		627,355		689,911
Current portion of indebtedness		—		—
Noncurrent portion of indebtedness	$	627,355	$	689,911

8.25% Senior Notes

The 8.25% senior notes consist of $510.0 million in aggregate principal amount of our 8.25% senior notes due 2018 (the “8.25% Senior Notes”) issued under an Indenture dated February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest due semi-annually, in arrears, on February 15th and August 15th of each year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. The effective interest rate on the 8.25% Senior Notes is approximately 9.1%. We issued the 8.25% Senior Notes in two different private placements, described below.

On February 14, 2011, we issued the $210.0 million in aggregate principal amount of our 8.25% senior notes due 2018 (the “2011 Senior Notes”) under the 2011 Indenture. We used the net proceeds from the offering of the 2011 Senior Notes of $202.0 million, after deducting the initial purchasers’ discount and offering expenses payable by us, to acquire the ASOP Properties for a purchase price of $200.7 million, before adjustments to reflect an economic effective date of January 1, 2011.

On October 25, 2012, we issued the $300.0 million in aggregate principal amount of our 2012 Senior Notes under an Indenture dated as of October 25, 2012 (the “2012 Indenture”). We used the net proceeds from the offering of the 2012 Senior Notes of $289.5 million, after deducting the initial purchasers’ discount, to fund a portion of the Hilcorp Acquisition. The purchase price of the 2012 Senior Notes included $4.8 million of accrued interest for the period from August 15, 2012 to October 25, 2012, which we recorded as interest payable.

The 2012 Senior Notes were offered in a private placement only to qualified institutional buyers under Rule 144A promulgated under the Securities Act of 1933, as amended (the “Securities Act”), or to persons outside of the United States in compliance with Regulation S promulgated under the Securities Act. The 2012 Senior Notes had terms that were substantially identical to the terms of our 2011 Senior Notes. Pursuant to a registration rights agreement executed as part of the sale of the 2012 Senior Notes, we have issued publicly registered additional notes under our 2011 Indenture in exchange for the 2012 Senior Notes. As a result of this exchange offer, 100% in aggregate principal amount of the 2012 Senior Notes was exchanged for the notes under the 2011 Indenture, effective as of June 10, 2013. All of the 8.25% Senior Notes are now issued under the 2011 Indenture, regardless of which private placement they were issued under.

On or after February 15, 2015, we may on any one or more occasions redeem all or a part of the 8.25% Senior Notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest and special interest, if any, on the notes redeemed, to the applicable date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date:

Year	Percentage
2015		104.125	%
2016		102.063	%
2017 and thereafter		100.000	%

Any such redemption and notice may, in our discretion, be subject to the satisfaction of one or more conditions, precedent, including, but not limited to, the occurrence of a change of control. Unless we default in the payment of the redemption price, interest will cease to accrue on the 8.25% Senior Notes or portions thereof called for redemption on the applicable redemption date.

At any time prior to February 15, 2014, we may, at our option, on any one or more occasions redeem with the net cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of outstanding 8.25% Senior Notes, upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 108.25% of the principal amount of the notes redeemed, plus the accrued and unpaid interest and special interest, if any, to the redemption date, provided that: (1) at least 65% of the aggregate principal amount of notes issued under the 2011 Indenture remains outstanding immediately after the occurrence of such redemption; and (2) the redemption occurs within 90 days of the date after the closing of such equity offering. This option to redeem up to 35% of the aggregate principal amount of outstanding 8.25% Senior Notes with the net cash proceeds of certain equity offerings is considered an embedded derivative. We estimate that the fair value of this option at December 31, 2013 is not material. In addition, we may, at our option, on any one or more occasions redeem all or a part of the 8.25% Senior Notes prior to February 15, 2015 at a redemption price equal to 100% of the principal amount of the 8.25% Senior Notes redeemed plus a “make-whole” premium as of, and accrued and unpaid interest to the redemption date.

If we experience a change of control (as defined in the 2011 Indenture), each holder of the 8.25% Senior Notes will have the right to require us to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of the 8.25% Senior Notes at a price in cash equal to 101% of the aggregate principal amount of the 8.25% Senior Notes repurchased, plus accrued and unpaid interest to the date of repurchase. If we engage in certain asset sales, within 360 days of such sale, we generally must use the net cash proceeds from such sales to repay outstanding senior secured debt (other than intercompany debt or any debt owed to an affiliate), to acquire all or substantially all of the assets, properties or capital stock of one or more companies in our industry, to make capital expenditures or to invest in our business. When any such net proceeds that are not so applied or invested exceed $20.0 million, we must make an offer to purchase the 8.25% Senior Notes and other pari passu debt that is subject to similar asset sale provisions in an aggregate principal amount equal to the excess net cash proceeds. The purchase price of each 8.25% Senior Note (or other pari passu debt) so purchased will be 100% of its principal amount, plus accrued and unpaid interest to the repurchase date, and will be payable in cash.

The 2011 Indenture, among other things, limits our ability to: (i) declare or pay dividends, redeem subordinated debt or make other restricted payments; (ii) incur or guarantee additional debt or issue preferred stock; (iii) create or incur liens; (iv) incur dividend or other payment restrictions affecting restricted subsidiaries; (v) consummate a merger, consolidation or sale of all or substantially all of our assets; (vi) enter into sale-leaseback transactions, (vii) enter into transactions with affiliates; (viii) transfer or sell assets; (ix) engage in business other than our current business and reasonably related extensions thereof; or (x) issue or sell capital stock of certain subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the 2011 Indenture.

Senior Credit Facility

On February 14, 2011, we entered into our senior secured credit facility with BMO Capital Markets, as lead arranger, and Bank of Montreal, as administrative agent and a lender, and the other lender parties thereto (as amended and restated, the “Senior Credit Facility”). The original terms of our Senior Credit Facility established a revolving credit facility with a four-year term that could be used for revolving credit loans and letters of credit up to an aggregate principal amount of $250.0 million. On October 31, 2012, in connection with the Hilcorp Acquisition, through an amendment and restatement of our Senior Credit Facility, the aggregate commitment under this facility was increased to a maximum of $750.0 million and the maturity date was extended to October 31, 2016. The maximum amount of letters of credit that may be outstanding at any one time is $20.0 million. The amount available under the revolving credit facility is limited by the borrowing base. The borrowing base under our Senior Credit Facility has been determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations. On October 31, 2012, the borrowing base under the expanded credit facility was increased from $200.0 million to $425.0 million. On November 26, 2013, we completed our semi-annual redetermination and our borrowing base remained at $425.0 million. In January 2014, our lenders approved a $50.0 million increase in our borrowing base under the $750.0 million facility, increasing our borrowing base to $475.0 million. In addition, in July 2013, our Senior Credit Facility was amended to increase the limit applicable to certain restricted payments permitted by the agreement to accommodate our expanded stock repurchase program. As of December 31, 2013 and 2012, we had outstanding under the Senior Credit Facility $130.0 million and $195.0 million, respectively.

The interest rate spread on loans and letters of credit under our Senior Credit Facility is based on the level of utilization and range from a base rate plus a margin of 0.75% to 1.75% for base rate borrowings and LIBOR plus a margin of 1.75% to 2.75% for LIBOR borrowings. Commitment fees ranging from 0.375% to 0.50% are payable on the unused portion of the borrowing base. Interest on our base rate borrowings is payable quarterly, in arrears, and interest on our LIBOR borrowings is payable on the last day of each relevant interest period, except that in the case of any interest period that is longer than three months, interest is payable on each successive date three months after the first day of such interest period.

Our Senior Credit Facility contains customary covenants, default provisions and collateral requirements. As described in the agreement underlying our Senior Credit Facility, we must maintain, for each period for which a covenant certification is required, (a) a minimum current ratio (as defined in the agreement for our Senior Credit Facility) of 1.0 to 1.0 and (b) a maximum total debt to EBITDAX ratio of 3.5 to 1.0. We are also required to maintain a commodities hedging program that is in compliance with the requirements set forth in our Senior Credit Facility. Our Senior Credit Facility also places restrictions on the maximum estimated future production volumes that can be subject to commodity derivative instruments.

Our obligations under our Senior Credit Facility, as well as any hedging contracts and treasury management agreements with the lenders or affiliates of lenders, are secured by substantially all of our assets, including a) mortgages on at least 80% of the total value of our oil and gas properties evaluated in the most recently completed reserve report, after giving effect to exploration and production activities, acquisitions and dispositions, and b) the stock of certain wholly-owned subsidiaries.

(8)

Concentrations

Significant Customers

We had oil and natural gas sales to three customers accounting for 63%, 24% and 6%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2013. We had oil and natural gas sales to three customers accounting for 45%, 31% and 11%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2012. We had oil and natural gas sales to three customers accounting for 51%, 17% and 12%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2011.

Geographic Concentration

Virtually all of our current operations and proved reserves are concentrated in the Gulf of Mexico region. Therefore, we are exposed to operational, regulatory and other risks associated with the Gulf of Mexico, including the risk of adverse weather conditions. We maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed.

(9)

Derivative Instruments and Hedging Activities

We enter into derivative instruments to reduce exposure to fluctuations in the price of oil and natural gas for a portion of our production. Our fixed-price swaps fix the sales price for a limited amount of our production and, for the contracted volumes, eliminate our ability to benefit from increases in the sales price of the production. Derivative instruments are carried at their fair value on the consolidated balance sheets as Fair value of commodity derivative instruments and all gains and losses due to changes in fair market value and contract settlements are recorded in Gain (loss) on derivative instruments in Other income (expense) in the consolidated statements of operations. See Note 10 for information regarding fair values of our derivative instruments.

The following tables set forth our derivative instruments outstanding as of December 31, 2013.

Oil Contracts

	Fixed-Price Swaps
	Daily Average Volume (Bbls		Volume (Bbls)		Average Swap Price ($/Bbl)
Remaining Contract Term
January 2014		16,350		506,850		93.11
February 2014		16,350		457,800		93.11
March 2014		16,350		506,850		93.11
April 2014		15,350		460,500		94.27
May 2014		15,350		475,850		94.27
June 2014		15,350		460,500		94.27
July 2014		14,350		444,850		93.56
August 2014		8,750		271,250		94.28
September 2014		8,750		262,500		94.28
October 2014		8,750		271,250		94.28
November 2014		8,750		262,500		94.28
December 2014		11,700		362,700		91.90
2014 Total		12,996		4,743,400		93.67

January 2015 - December 2015		1,500		547,500		97.70

Gas Contracts

	Fixed-Price Swaps
	Daily Average Volume (Mmbtu)		Volume (Mmbtu)		Average Swap Price ($/Mmbtu)
Remaining Contract Term
January 2014 - December 2014		5,000		1,825,000		4.01
January 2015 - December 2015		4,300		1,569,500		4.31

The following table presents information about the components of loss on derivative instruments.

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Change in fair market value	$	(20,884	)	$	(9,491	)	$	11,475
Loss on settlement		(11,477	)		(3,814	)		(17,345	)
Total loss on derivative instruments	$	(32,361	)	$	(13,305	)	$	(5,870	)

(10)

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820, “Fair Value Measurements and Disclosures,” establishes a fair value hierarchy with three levels based on the reliability of the inputs used to determine fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets and 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 December 31, 2013 and 2012, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, primarily our commodity derivative instruments. The fair values of derivative instruments were measured using price inputs published by NYMEX and IntercontinentalExchange, Inc., or ICE. These price inputs are quoted prices for assets and liabilities similar to those held by us and meet the definition of Level 2 inputs within the fair value hierarchy. The following table sets forth our financial assets and liabilities that are accounted for at fair value on a recurring basis.

	December 31.
	2013			2012
	(in thousands)
Assets:
Current	$	501		$	3,302
Noncurrent		238			211
Total gross fair value		739			3,513
Less: counterparty set-off		(739	)		(3,513	)
Total net fair value		-			-

Liabilities:
Current	$	29,636		$	10,026
Noncurrent		2,136			3,637
Total gross fair value		31,772			13,663
Less: counterparty set-off		(739	)		(3,513	)
Total net fair value		31,033			10,150

The carrying values reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short term maturities of these instruments. The fair value for the 8.25% Senior Notes is based on quoted prices, which are Level 1 inputs within the fair value hierarchy. The carrying value of the Senior Credit Facility approximates its fair value because the interest rates are variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

The following table sets forth the carrying values and estimated fair values of our long-term indebtedness.

	December 31, 2013				December 31, 2012
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% Senior Notes	$	497,355	$	546,338	$	494,911	$	524,600
Senior Credit Facility		130,000		130,000		195,000		195,000
Total	$	627,355	$	676,338	$	689,911	$	719,600

We evaluate our capitalized costs of proved oil and natural gas properties for potential impairment when circumstances indicate that the carrying values may not be recoverable. Our assessment of possible impairment of proved oil and natural gas properties is based on our best estimate of future prices, costs and expected net future cash flows by property (generally analogous to a field or lease). An impairment loss is indicated if undiscounted net future cash flows are less than the carrying value of a property. The impairment expense is measured as the shortfall between the net book value of the property and its estimated fair value, which is measured based on the discounted net future cash flows from the property. The inputs used to estimate the fair value of our oil and natural gas properties are based on our estimates of future events, including projections of future oil and natural gas sales prices, amounts of recoverable oil and natural gas reserves, timing of future production, future costs to develop and produce our oil and natural gas and discount factors. These inputs meet the definition of Level 3 inputs within the fair value hierarchy. Impairments for the year ended December 31, 2013 were primarily related to reservoir performance at a gas well in one of our smaller producing fields. This field was determined to have future net cash flows less than its carrying value resulting in the write down of this property to its estimated fair value. Impairments for the year ended December 31, 2012 were primarily due to the decline in our estimate of future natural gas prices, which affected three of our natural gas producing fields and reservoir performance at two of those fields. These fields were determined to have future net cash flows less than their carrying values resulting in the write downs of these properties to their estimated fair values. We also recorded impairments for undeveloped leases that are expiring in 2013 for which we had no development plans. Impairments for the year ended December 31, 2011 were primarily related to our natural gas producing fields and our deepwater producing well (primarily natural gas). Impairments related to our deepwater producing well were primarily due to the decline in our estimate of future natural gas prices, reservoir performance and higher estimated operating costs. Additional impairments for the year ended December 31, 2011 were primarily related to reservoir performance at other natural gas producing fields.

As addressed in Note 2, “Acquisitions,” we apply fair value concepts in estimating and allocating the fair value of assets acquired and liabilities assumed in acquisitions in accordance with purchase accounting for business combinations. The inputs to the estimated fair values of assets acquired and liabilities assumed are described in Note 2.

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Income Taxes

The following table sets forth the components of our provision for income taxes.

	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Current:
Federal	$	-		$	-		$	-
State		-			-			-
Total current	$	-		$	-		$	-

Deferred:
Federal	$	(47,723	)	$	(28,719	)	$	(14,468	)
State		(1,964	)		(1,181	)		(354	)
Total deferred		(49,687	)		(29,900	)		(14,822	)

Total:
Federal	$	(47,723	)	$	(28,719	)	$	(14,468	)
State		(1,964	)		(1,181	)		(354	)
Total provision for income taxes.	$	(49,687	)	$	(29,900	)	$	(14,822	)

The following table reconciles the expected statutory federal income tax rate to our effective income tax rate.

	Percentage of Pretax Earnings
	Year Ended December 31,
	2013			2012			2011
Expected statutory federal income tax rate		35.0			35.0			35.0
State taxes		1.4			1.4			2.3
State tax rate changes		-			(2.7	)		(1.7	)
Statutory depletion		(0.3	)		(0.4	)		(1.0	)
Other		0.7			0.4			1.2
Effective income tax rate		36.8			33.7			35.8

The following table sets forth the tax effects of temporary differences that give rise to significant portions of our deferred tax assets and liabilities.

	December 31.
	2013		2012
	(in thousands)
Deferred tax assets:
Federal and state net operating loss carryforwards	$	62,015	$	62,130
Fair value of commodity derivative instruments		11,578		3,912
Restricted stock awards and options		3,843		2,313
Percentage depletion carryforward		5,003		4,575
Accruals and other		1,130		2,613
Deferred tax asset		83,569		75,543

Deferred tax liabilities:
Property, plant and equipment, principally due to differences in depreciation	$	193,191	$	136,016
Fair value of commodity derivative instruments		182		214
Prepaid assets		1,482		1,778
Accruals and other		2,577		1,907
Deferred tax liabilities		197,432		139,915

	December 31.
	2013		2012
	(in thousands)
Net deferred tax liability		113,863		64,372

Reflected in accompanying balance sheets as:
Current deferred asset		8,949		3,322
Non-current deferred liability		122,812		67,694
Total net deferred tax liability	$	113,863	$	64,372

As a result of our reorganization under Chapter 11 in 2009, the income from the discharge of indebtedness, represented for tax purposes as the excess of the principal and accrued interest on the debt discharged over the fair value of the stock of the reorganized company received in exchange for the discharged obligations, as defined by Internal Revenue Code (the “IRC”) Section 108 (“IRC 108”), reduced our net operating loss carryforwards (“NOLs”) by $97 million (“Tax Attribute Reduction”). Our remaining NOLs as of December 31, 2013 were approximately $167 million.

Ownership changes, as defined in IRC Section 382, limit the amount of NOLs that can be utilized annually to offset future taxable income and reduce our tax liability (“Section 382 Limitation”). In 2009, as part of our Chapter 11 reorganization, we had an ownership change which resulted in a Section 382 Limitation on the amount of NOLs available annually for use. Unused annual limited NOLs (those NOLs in existence immediately after the application of IRC 108) totaled $137 million. The annual limitation is approximately $21 million per year beginning in 2010 and, if unused, can be carried over and aggregated with limited NOLs in future years subject to the ultimate expiration of the NOLs. We have not used any limited NOLs since the reorganization. The amount of limited NOLs available for our 2013 federal tax return is approximately $121 million. We believe that we will be able to utilize all of our federal NOLs prior to their expiration.

At December 31, 2013, we had approximately $167 million of federal NOLs, of which approximately $3.8 million relates to excess tax benefits with respect to share-based compensation that have not been recognized in our consolidated financial statements. Our federal NOLs are available to reduce future federal taxable income subject to the limitations and estimates described above and the application of the tax rules and regulations. The NOLs begin expiring in the years 2025 through 2033.

As of January 1, 2013, our 2009-2012 income tax years remain subject to examination by the Internal Revenue Service. In addition, our 2009-2012 state income/franchise tax years remain subject to examination by the States of Louisiana and Texas. As of the date of these financial statements, our 2013 U.S. federal and state income tax returns have not been filed, although management expects to file such returns in a timely manner during 2014. We have no material uncertain tax positions as of December 31, 2013.

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Employee Benefit Plans

Share-Based Compensation Plans

In September 2009 the Board of Directors adopted the 2009 Long Term Incentive Plan (the “2009 LTIP”). The purpose of the 2009 LTIP is to provide a means to enhance our profitable growth by attracting and retaining directors, officers and other key employees through affording such individuals a means to acquire and maintain stock ownership or awards the value of which is tied to the performance of our common stock. All directors, officers and other key employees providing services to the Company are potentially eligible to participate in the 2009 LTIP. The 2009 LTIP provides for grants of (i) incentive stock options qualified as such under income tax rules and regulations, (ii) stock options that do not qualify as incentive stock options, (iii) restricted stock awards, (iv) restricted stock units, (v) stock appreciation rights, (vi) bonus stock and awards in lieu of Company obligations, (vii) dividend equivalents in connection with other awards, (viii) deferred shares, (ix) performance units or shares, or (x) any combination of such awards (collectively referred to as “Awards”). The 2009 LTIP is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”).

Without stockholder or participant approval, the Board of Directors may amend, alter, suspend, discontinue or terminate the 2009 LTIP or the Compensation Committee’s authority to grant Awards under the 2009 LTIP, except that any amendment or alteration of the 2009 LTIP, including any increase in any share limitation, shall be subject to the approval of the stockholders not later than the next annual meeting if stockholder approval is required by any state or federal law or regulation or the rules of any stock exchange or automated quotation system on which the common stock may then be listed or quoted.

On the date of the 2013 Annual Meeting of Stockholders, the stockholders approved an increase in the maximum aggregate number of shares of our common stock that may be issued pursuant to any and all Awards under the 2009 LTIP from 2,474,000 shares to 3,574,000 shares, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of Awards, as provided under the 2009 LTIP. As of December 31, 2013, 1,184,322 shares remained available for future grants.

The 2009 LTIP provides for the grant of stock options for which the exercise price, set at the time of the grant, will not be less than the fair market value per share at the date of grant. Our outstanding stock options generally have a term of 10 years and vest ratably on an annual basis over a three-year period from the date of grant, other than the stock option grant to our chief executive officer described in the following paragraph.

Pursuant to an employment agreement and the 2009 LTIP, on September 30, 2009, our new chief executive officer was granted an option to purchase 68,116 shares of our common stock, which was memorialized in an option award agreement dated as of October 1, 2009 (the “Option Agreement”). The terms of the Option Agreement provided for an exercise price equal to $10.00 per share. The closing price of our common stock on the NYSE on September 30, 2009 was $7.46 per share. The option vested ratably on a monthly basis over a 36-month period from the date of grant; however, the vesting for the first six months of the vesting period (the “Initial Period”) was deferred until the end of the Initial Period and any remaining unvested portion vested ratably on a monthly basis over the remainder of the 36-month vesting period, subject to the executive remaining continuously employed. Under the original terms of the award agreement, vested stock options under the Option Agreement were to expire 30 months following the applicable vesting date of such stock options. On May 1, 2012, the Compensation Committee modified the terms of the Option Agreement to extend the expiration of the stock options granted thereunder to September 30, 2019, resulting in additional compensation expense of $0.1 million in the year ended December 31, 2012. Upon a change in control as defined in the 2009 LTIP, all stock options under the Option Agreement remain exercisable for a period of not less than 30 months following the change in control.

In November 2009, the Compensation Committee approved a compensation program for each of our non-employee directors which provides for the annual grant of a stock award with a market value of $100,000 (as measured on the date of grant and prorated from the date of grant, as applicable). Pursuant to the terms of the program, one-half of each stock award vests immediately on the date of grant, and the remaining one-half vests immediately prior to the next annual meeting of stockholders held after the grant date. The grant date for these awards is typically on the date of our annual meeting of stockholders. Pursuant to this program and the 2009 LTIP, the five members of the Board of Directors were awarded, in the aggregate, a total of 15,305 shares, a total of 31,095 shares and a total of 31,405 shares during the years ended December 31, 2013, 2012, and 2011, respectively. Pursuant to elections made by two directors applicable to certain of these awards, the receipt of such awards totaling 39,009 shares is deferred until such directors cease to serve on our Board of Directors. During the year ended December 31, 2013, one of our non-employee directors resigned, forfeiting 1,531 shares awarded under this program.

The following table sets forth our stock option activity for the year ended December 31, 2013.

	Options			Weighted- Average Exercise Price Per Share		Weighted- Average Remaining Contractual Terms	Aggregate Intrinsic Value
						(in years)	(in thousands)
Outstanding on December 31, 2012		1,192,158		$	14.30
Granted		369,137			27.48
Exercised		(108,122	)		12.80
Forfeited/Cancelled		-			-

	Options		Weighted- Average Exercise Price Per Share		Weighted- Average Remaining Contractual Terms		Aggregate Intrinsic Value
Outstanding on December 31, 2013		1,453,173		17.76		7.8	$	15,970
Exercisable on December 31, 2013		705,814		13.45		6.9	$	10,624

The fair value of each stock option award was estimated on the date of grant using the Black-Scholes option valuation model using the weighted average assumptions in the table below.

	Year Ended December 31,
	2013			2012			2011
Black-Scholes option pricing model assumptions:
Risk free interest rate		1.4	%		1.0	%		1.9	%
Expected life (years)		6.0			6.0			6.0
Expected volatility		56	%		56	%		53	%
Dividend yield		-			-			-

Expected volatility is generally based on the historical volatility of our stock over the period of time equivalent to the expected term of the options granted. As a result of our Chapter 11 reorganization in 2009 for purposes of determining expected volatility in 2013, 2012 and 2011, we included consideration of the historical volatility of the share prices of our peers over the relevant time periods in addition to our historical volatility before, during and after our reorganization. We disregarded our share price for the periods during which our stock price was impacted by factors leading up to the Chapter 11 filing and during the period of the Chapter 11 reorganization proceedings because we do not expect these events to reoccur during the expected term of the options. The expected term of options granted is generally derived from historical exercise patterns over a period of time, with consideration of the expected term of unvested options. However, because we do not have sufficient historical stock option exercise experience upon which to base an estimate of expected term, we used the simplified method for estimating expected term in 2013, 2012 and 2011. The risk-free interest rate is based on the interest rate on constant maturity bonds published by the Federal Reserve with a maturity commensurate with the expected term of the options granted.

The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2013, 2012 and 2011 was $14.50, $8.84 and $7.97, respectively. The aggregate intrinsic value (the amount by which the market price of the stock on the date of exercise exceeded the market price of the stock on the date of grant) of stock options exercised during the years ended December 31, 2013, 2012 and 2011 was $2.1 million, $0.5 million and $0.1 million, respectively.

The following table sets forth the activity related to our non-vested share awards for the year ended December 31, 2013.

	Shares			Weighted- Average Grant- Date Fair Value
Non-vested share awards outstanding at December 31, 2012		326,952		$	15.98
Granted		264,383			26.60
Vested		(145,309	)		16.77
Forfeited		(1,531	)		32.67
Non-vested share awards outstanding at December 31, 2013		444,495		$	21.98

The fair value of non-vested share awards equals the market value of the underlying stock on the date of grant. The weighted-average grant-date fair value of the non-vested share awards granted during the years ended December 31, 2013, 2012 and 2011 was $26.60, $16.33 and $15.34 per share, respectively. The total fair value of non-vested share awards that vested during the years ended December 31, 2013, 2012 and 2011 was $4.1 million, $2.0 million and $0.6 million, respectively.

The following table sets forth share-based compensation expense and related recognized tax benefits.

	Year Ended December 31,
	2013		2012		2011
Compensation Expense:
Stock Options	$	3,426	$	2,621	$	1,497
Non-vested share awards		3,918		2,096		1,012
Deferred Income Tax Benefit		2,704		1,726		936

As of December 31, 2013, $5.6 million of total unrecognized compensation expense related to outstanding stock options was expected to be recognized over a weighted-average period of 2.0 years. As of December 31, 2013, $6.1 million of total unrecognized compensation expense related to non-vested share awards was expected to be recognized over a weighted-average period of approximately 2.0 years.

401(k) Plan

We also have a 401(k) Plan that covers all employees. We match 100% of each individual participant’s contribution not to exceed 6% of the participant’s compensation. Our matching contributions are made in cash. During the years ended December 31, 2013, 2012 and 2011, we made matching contributions to the 401(k) Plan of approximately $0.9 million, $0.8 million and $0.7 million, respectively.

Employee Retention Plans

The Company has two plans under which, in the event of termination of employment in connection with a change of control of our company, our officers and employees are entitled to receive a multiple of their salaries and bonuses (typically up to one or two-and-one-half times such amount) and certain other benefits in a lump sum cash payment. Additionally, all options, restricted stock, restricted share units and other similar awards would become fully vested.

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Commitments and Contingencies

We have operating leases for office space and equipment, which expire on various dates through 2019. Expense relating to operating obligations for the years ended December 31, 2013, 2012 and 2011 was $7.5 million, $2.4 million and $1.8 million, respectively. Future minimum commitments as of December 31, 2013 under these operating obligations are as follows (in thousands):

2014		1,073
2015		1,222
2016		1,239
2017		661
2018		542
Thereafter		406
Future minimum commitments	$	5,143

In connection with our exploration and development efforts, we are contractually committed to the acquisition of seismic data in the aggregate amount of $40.5 million to be incurred over the next four years.

We maintain restricted escrow funds in a trust for future abandonment costs at our East Bay property. The trust was originally funded with $15.0 million and, with accumulated interest, increased to $16.7 million at December 31, 2008. We may draw from the trust upon completion of qualifying abandonment activities at our East Bay field. At December 31, 2013, we had $6.0 million remaining in restricted escrow funds for decommissioning work in our East Bay field, which will remain restricted until substantially all required decommissioning in the East Bay field is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our consolidated balance sheets.

We record liabilities when we deliver production that is in excess of our interest in certain properties. In addition to these imbalances, we may, from time to time, be allocated cash sales proceeds in excess of amounts that we estimate are due to us for our interest in production. These allocations may be subject to further review, may require more information to resolve or may be in dispute. In July 2010, we were notified by a purchaser of oil production from one of our non-operated fields that we were allocated, and received sales proceeds from, more oil production than we actually sold to that purchaser. The oil purchaser’s initial estimate of the oil volumes misallocated to us was approximately 74,000 barrels, which may have been valued at up to $6.9 million based on information provided by the oil purchaser. We had previously recorded an amount that we believed may have been payable related to a potential reallocation, which amount was reflected in Accrued expenses in the accompanying consolidated balance sheet as of December 31, 2012. In connection with the sale of the BM Interests in 2013, the buyer assumed any liability we may have had related to this matter.

We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments, increases or decreases, to our net costs or revenues and the related cash flows. Such adjustments may be material. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account.

We are a defendant in a number of lawsuits and are involved in governmental and regulatory proceedings, all of which arose in the ordinary course of business, including, but not limited to, personal injury claims, royalty claims, contract claims, and environmental claims, including claims involving assets owned by acquired companies. While the ultimate outcome and impact on us cannot be predicted with certainty, management believes that the resolution of pending proceedings will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

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Interim Financial Information (Unaudited)

The following tables summarize our consolidated unaudited interim financial information for the years ended December 31, 2013 and 2012.

	Three Months Ended
	March 31		June 30		September 30⁽¹⁾			December 31⁽²⁾
	(In thousands, except per share data)
2013
Revenues	$	182,349	$	184,087	$	183,992		$	142,610
Costs and expenses		109,657		98,535		143,178			122,077
Income from operations		72,692		85,552		40,814			20,533
Net income (loss)		29,037		69,579		(1,284	)		(12,058	)
Earnings (loss) per share:
Basic	$	0.74	$	1.77	$	(0.03	)	$	(0.31	)
Diluted		0.73		1.75		(0.03	)		(0.31	)

________________

(1)

Included in net income (loss) for the three months ended September 30, 2013 is the loss on abandonment activities totaling $22.6 million resulting from an increase in required scope of work attributable to changes in regulatory interpretations and enforcement by BSEE in the deepwater.

(2)

The decrease in revenue for the quarter ended December 31, 2013 compared to the quarter ended September 30, 2013 is primarily due to a decrease in oil production and a decrease in the average selling prices of our oil.

	Three Months Ended
	March 31		June 30		September 30⁽¹⁾			December 31⁽²⁾
	(In thousands, except per share data)
2012
Revenues	$	98,796	$	99,270	$	86,668		$	138,899
Costs and expenses		71,501		68,071		67,379			86,235
Income from operations		27,295		31,199		19,289			52,664
Net income (loss)		1,503		35,401		(2,247	)		24,153
Earnings (loss) per share:
Basic	$	0.04	$	0.90	$	(0.06	)	$	0.62
Diluted		0.04		0.90		(0.06	)		0.61

________________

(1)

Includes the results of operations of the Hilcorp Properties, which we acquired on October 31, 2012.

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Supplementary Oil and Natural Gas Disclosures—(Unaudited)

Our estimates of proved reserves are based on a reserve report prepared as of December 31, 2013 by the independent petroleum engineering firm Netherland, Sewell & Associates, Inc. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant professional judgment in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the professional judgment required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

The following table sets forth our estimated net proved reserves, changes in our estimated net proved reserves and our net proved developed and undeveloped reserves.

	Oil (Mbbls)			Gas (Mmcf)			Oil Equivalent (Mboe)
Estimated Proved Reserves:
December 31, 2010		17,223			61,251			27,431
Acquisitions (a)		7,987			8,640			9,427
Extensions and discoveries		2,266			4,664			3,043
Revisions		2,778			(6,678	)		1,666
Production		(2,953	)		(9,092	)		(4,468	)
December 31, 2011		27,301			58,785			37,099
Acquisitions (b)		16,430			115,876			35,742
Extensions and discoveries (c)		6,388			10,241			8,095
Revisions		1,128			4,033			1,800
Production		(3,805	)		(8,996	)		(5,304	)
December 31, 2012		47,442			179,939			77,432
Acquisitions		366			209			401
Sales		(1,415	)		(916	)		(1,568	)
Extensions and discoveries (d)		7,354			20,247			10,729
Revisions		3,952			(10,128	)		2,264
Production		(6,182	)		(15,767	)		(8,810	)
December 31, 2013		51,517			173,584			80,448
Proved developed reserves:
December 31, 2011		24,791			52,739			33,581
December 31, 2012		37,908			120,687			58,022
December 31, 2013		39,439			107,687			57,387
Proved undeveloped reserves:
December 31, 2011		2,510			6,046			3,518
December 31, 2012		9,534			59,252			19,409
December 31, 2013		12,078			65,897			23,061

________________

(a)

Reserves acquired in the acquisitions of the ASOP Properties and Main Pass Interests.

(b)

Reserves acquired in the acquisitions of the Hilcorp Properties and the ST41 Interests.

(c)

Includes extensions and discoveries across 6 different fields, primarily within our West Delta and Ship Shoal areas. These extensions and discoveries added volumes ranging from 18 Mboe to 1.2 Mmboe each, with three exceeding 1.0 Mmboe each.

(d)

Includes extensions and discoveries across 12 different fields, primarily within our Ship Shoal and West Delta areas. The Ship Shoal 208 field accounts for 46% of our total extensions and discoveries with 4,973 Mboe, consisting of 3,967 Mbbls of oil and 6,035 Mmcf of produced gas. The remaining 11 locations account for up to 16% each of total extensions and discoveries with reserves ranging from 10 Mboe to 1.6 Mmboe.

Capitalized costs for oil and natural gas producing activities consist of the following:

	Year Ended December 31,
	2013			2012
	(In thousands)
Proved properties	$	2,307,891		$	1,982,657
Unproved properties		39,191			36,992
Accumulated depreciation, depletion and amortization		(614,068	)		(424,520	)
Net capitalized costs	$	1,733,014		$	1,595,129

The following table sets forth the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves.

	Year Ended December 31,
	2013		2012		2011
	(In thousands)
Acquisitions — Proved (1)	$	46,047	$	706,322	$	261,812
Acquisitions — Unproved		2,200		7,496		14
Exploration		46,100		43,338		17,129
Development (2)		303,245		180,938		83,577
Costs incurred	$	397,592	$	938,094	$	362,532

________________

(1)

For the year ended December 31, 2013, includes $29.7 million associated with the Hilcorp Acquisition and $16.7 million associated with the WD29 Acquisition. See Note 2, “Acquisitions and Dispositions” for more information.

(2)

Includes our estimates during the years ended December 31, 2013, 2012 and 2011 of incurred asset retirement obligations associated with finding and developing our proved oil and natural gas reserves of $1.2 million, $1.2 million and $0.2 million, respectively.

Expenditures incurred for exploratory dry holes are included in investing activities in the consolidated statements of cash flows.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by ASC 932. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of our oil and natural gas reserves or the current value of the Company.

We believe that the following factors should be taken into account in reviewing the following information: (1) future costs and sales prices are likely to differ materially from those required to be used in these calculations; (2) due to future market conditions, governmental regulations and other factors, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) the use of a 10% discount rate, while mandated under ASC 932, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

The Standardized Measure of Discounted Future Net Cash Flows uses future cash inflows estimated using oil and natural gas prices computed by applying the use of physical pricing based on the simple average of the closing price on the first day of each of the twelve months during the fiscal year (as required by ASC 932) and by applying historical adjustments, including transportation, quality differentials, and purchaser bonuses, on an individual property basis, to the year-end quantities of estimated proved reserves. The historical adjustments applied to the computed prices are determined by comparing our historical realized price experience with the comparable historical market, or posted, price. These adjustments can vary significantly over time both in amount and as a percentage of the posted price, especially related to our oil prices during periods when the market price for oil varies widely. The price adjustments reflected in our computed reserve prices may not represent the amount of price adjustments we may actually obtain in the future when we sell our production, nor do they give effect to any hedging transactions that we may enter into. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs with the assumption of the continuation of existing economic conditions in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% annual discount rate in computing Standardized Measure of Discounted Future Net Cash Flows is required by ASC 932.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

	Year Ended December 31,
	2013			2012
	(In thousands)
Future cash inflows	$	5,937,536		$	5,401,290
Future production costs		(1,957,868	)		(1,823,303	)
Future development costs (1)		(1,085,440	)		(936,580	)
Future income taxes		(641,536	)		(537,546	)
Future net cash flows after income taxes		2,252,692			2,103,861
10% annual discount for estimated timing of cash flows		(603,614	)		(529,579	)
Standardized measure of discounted future net cash flows	$	1,649,078		$	1,574,282

________________

(1)

Future development costs as of December 31, 2013, include $569.9 million of estimated abandonment and decommissioning costs, net of $25.8 million of estimated salvage values. Future development costs as of December 31, 2012 include $466.9 million of estimated abandonment and decommissioning costs, net of $32.6 million of estimated salvage values.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2013 and 2012 is as follows:

	Year Ended December 31,
	2013			2012
	(In thousands)
Beginning of the period	$	1,574,282		$	876,169
Sales and transfers of oil and natural gas produced, net of production costs		(513,906	)		(317,059	)
Net changes in prices and production costs		96,751			(244,824	)
Purchase of minerals in place		26,708			797,085
Sales of minerals in place		(64,539	)		-
Extensions, discoveries and improved recoveries, net of future production costs		363,493			452,258
Revision of quantity estimates		84,490			55,133
Previously estimated development costs incurred during the period		33,920			39,321
Changes in estimated future development costs		18,229			746
Changes in production rates (timing) and other		(113,022	)		(14,157	)
Accretion of discount		197,927			110,070
Net change in income taxes		(55,255	)		(180,460	)
Net increase (decrease)		74,796			698,113
End of period	$	1,649,078		$	1,574,282

At December 31, 2013 and 2012, the computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was based on the following computed prices:

	2013		2012
per barrel of oil	$	105.30	$	105.13
per Mcf for natural gas	$	3.73	$	2.92

(16)

Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 7, all of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries) each of which is 100% owned by EPL Oil & Gas, Inc. (the “Guarantor Subsidiaries”) jointly and severally guaranteed the payment obligations under our 8.25% Senior Notes. The guarantees are full and unconditional, as those terms are used in Rule 3-10 of Regulation S-X, except that a Guarantor Subsidiary can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2011 Indenture. So long as other applicable provisions of the indenture are adhered to, these customary circumstances include: when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, or when the Guarantor Subsidiary is sold or sells all of its assets. The following supplemental financial information sets forth, on a consolidating basis, the balance sheets, statements of operations and cash flow information for EPL Oil & Gas, Inc. (Parent Company Only) and for the Guarantor Subsidiaries. We have not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries, or for any individual Guarantor Subsidiary, because management has determined that such information is not material to investors.

The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. Certain reclassifications were made to conform all of the financial information to the financial presentation on a consolidated basis. The principal eliminating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2013

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	8,812		$	—		$	—		$	8,812
Trade accounts receivable – net		70,520			187			—			70,707
Intercompany receivables		39,085			—			(39,085	)		—
Fair value of commodity derivative instruments		501			—			—			501
Deferred tax asset		8,949			—			—			8,949
Prepaid expenses		6,868			—			—			6,868
Total current assets		134,735			187			(39,085	)		95,837
Property and equipment		2,041,689			313,530			—			2,355,219
Less accumulated depreciation, depletion, amortization and impairments		(526,736	)		(92,052	)		—			(618,788	)
Net property and equipment		1,514,953			221,478			—			1,736,431
Investment in affiliates		122,697			—			(122,697	)		—
Deposit for Nexen Acquisition		7,040			—			—			7,040
Restricted cash		6,023			—			—			6,023
Fair value of commodity derivative instruments		238			—			—			238
Deferred financing costs		10,106			—			—			10,106
Other assets		2,067			89			—			2,156
Total assets	$	1,797,859		$	221,754		$	(161,782	)	$	1,857,831
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	58,758		$	673		$	—		$	59,431
Intercompany payables		—			39,085			(39,085	)		—
Accrued expenses		131,111			14			—			131,125
Asset retirement obligations		51,601			—			—			51,601
Fair value of commodity derivative instruments		29,636			—			—			29,636
Total current liabilities		271,106			39,772			(39,085	)		271,793
Long-term debt		627,355			—			—			627,355
Asset retirement obligations		160,466			43,383			—			203,849
Deferred tax liabilities		106,910			15,902			—			122,812
Fair value of commodity derivative instruments		2,136			—			—			2,136
Other		673			—			—			673
Total liabilities		1,168,646			99,057			(39,085	)		1,228,618
Stockholders’ equity:
Preferred stock		—			—			—			—
Common stock		41			—			—			41
Additional paid-in capital		519,114			85,479			(85,479	)		519,114
Treasury stock, at cost		(31,157	)		—			—			(31,157	)
Retained earnings		141,215			37,218			(37,218	)		141,215
Total stockholders’ equity		629,213			122,697			(122,697	)		629,213
Total liabilities and stockholders' equity	$	1,797,859		$	221,754		$	(161,782	)	$	1,857,831

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2012

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,521		$	—		$	—		$	1,521
Trade accounts receivable – net		66,994			997			—			67,991
Intercompany receivables		55,575			—			(55,575	)		—
Fair value of commodity derivative instruments		3,302			—			—			3,302
Deferred tax asset		3,322			—			—			3,322
Prepaid expenses		9,873			—			—			9,873
Total current assets		140,587			997			(55,575	)		86,009
Property and equipment		1,754,294			271,353			—			2,025,647
Less accumulated depreciation, depletion, amortization and impairments		(353,526	)		(74,054	)		—			(427,580	)
Net property and equipment		1,400,768			197,299			—			1,598,067
Investment in affiliates		111,191			—			(111,191	)		—
Restricted cash		6,023			—			—			6,023
Fair value of commodity derivative instruments		211			—			—			211
Deferred financing costs		12,386			—			—			12,386
Other assets		2,841			90			—			2,931
Total assets	$	1,674,007		$	198,386		$	(166,766	)	$	1,705,627
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	34,740		$	32		$	—		$	34,772
Intercompany payables		—			55,575			(55,575	)		—
Accrued expenses		117,245			127			—			117,372
Asset retirement obligations		23,982			6,197			—			30,179
Fair value of commodity derivative instruments		10,026			—			—			10,026
Total current liabilities		185,993			61,931			(55,575	)		192,349
Long-term debt		689,911			—			—			689,911
Asset retirement obligations		187,790			17,141			—			204,931
Deferred tax liabilities		59,571			8,123			—			67,694
Fair value of commodity derivative instruments		3,637			—			—			3,637
Other		1,132			—			—			1,132
Total liabilities		1,128,034			87,195			(55,575	)		1,159,654
Stockholders’ equity:
Preferred stock		—			—			—			—
Common stock		40			—			—			40
Additional paid-in capital		510,469			85,479			(85,479	)		510,469
Treasury stock		(20,477	)		—			—			(20,477	)
Retained earnings		55,941			25,712			(25,712	)		55,941
Total stockholders’ equity		545,973			111,191			(111,191	)		545,973
Total liabilities and stockholders' equity	$	1,674,007		$	198,386		$	(166,766	)	$	1,705,627

Supplemental Condensed Consolidating Statement of Operations
Year Ended December 31, 2013

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	606,743		$	82,000		$	—		$	688,743
Other		689			3,606			—			4,295
Total revenue		607,432			85,606			—			693,038
Costs and expenses:
Lease operating		140,605			25,236			—			165,841
Transportation		3,548			20			—			3,568
Exploration expenditures and dry hole costs		22,265			4,290			—			26,555
Impairments		2,937			—			—			2,937
Depreciation, depletion and amortization		178,427			21,932			—			200,359
Accretion of liability for asset retirement obligations		23,196			5,103			—			28,299
General and administrative		28,137			—			—			28,137
Taxes, other than on earnings		1,084			10,406			—			11,490
Gain on sale of assets		(28,219	)		(462	)		—			(28,681	)
Other		34,072			870			—			34,942
Total costs and expenses		406,052			67,395			—			473,447
Income from operations		201,380			18,211			—			219,591
Other income (expense):
Interest income		99			—			—			99
Interest expense		(52,368	)		—			—			(52,368	)
Loss on derivative instruments		(32,361	)		—			—			(32,361	)
Income from equity investments		11,506			—			(11,506	)		—
Total other income (expense)		(73,124	)		—			(11,506	)		(84,630	)
Income before provision for income taxes		128,256			18,211			(11,506	)		134,961
Deferred income tax expense		(42,982	)		(6,705	)		—			(49,687	)
Net income	$	85,274		$	11,506		$	(11,506	)	$	85,274

Supplemental Condensed Consolidating Statement of Operations
Year Ended December 31, 2012

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	318,749		$	103,780		$	—		$	422,529
Other		15,152			952			(15,000	)		1,104
Total revenue		333,901			104,732			(15,000	)		423,633
Costs and expenses:
Lease operating		71,002			23,848			—			94,850
Transportation		611			4			—			615
Exploration expenditures and dry hole costs		18,790			9			—			18,799
Impairments		8,883			—			—			8,883
Depreciation, depletion and amortization		92,689			20,892			—			113,581
Accretion of liability for asset retirement obligations		10,551			5,014			—			15,565
General and administrative		22,845			15,363			(15,000	)		23,208
Taxes, other than on earnings		1,162			11,845			—			13,007
Other		5,496			(818	)		—			4,678
Total costs and expenses		232,029			76,157			(15,000	)		293,186
Income from operations		101,872			28,575			—			130,447
Other income (expense):
Interest income		136			—			—			136
Interest expense		(28,568	)		—			—			(28,568	)
Loss on derivative instruments		(13,305	)		—			—			(13,305	)
Income from equity investments		18,945			—			(18,945	)		—
Total other income (expense)		(22,792	)		—			(18,945	)		(41,737	)
Income before provision for income taxes		79,080			28,575			(18,945	)		88,710
Deferred income tax expense		(20,270	)		(9,630	)		—			(29,900	)
Net income	$	58,810		$	18,945		$	(18,945	)	$	58,810

Supplemental Condensed Consolidating Statement of Operations
Year Ended December 31, 2011

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	245,567		$	102,640		$	—		$	348,207
Other		15,007			113			(15,000	)		120
Total revenue		260,574			102,753			(15,000	)		348,327
Costs and expenses:
Lease operating		51,618			18,663			—			70,281
Transportation		766			13			—			779
Exploration expenditures and dry hole costs		14,045			223			—			14,268
Impairments		32,532			(66	)		—			32,466
Depreciation, depletion and amortization		82,168			22,456						104,624
Accretion of liability for asset retirement obligations		9,013			6,929						15,942
General and administrative		18,281			15,460			(15,000	)		18,741
Taxes, other than on earnings		(733	)		15,098			—			14,365
Other		9,940			(205	)		—			9,735
Total costs and expenses		217,630			78,571			(15,000	)		281,201
Income from operations		42,944			24,182			—			67,126
Other income (expense):
Interest income		102			—			—			102
Interest expense		(17,548	)		—			—			(17,548	)
Loss on derivative instruments		(5,870	)		—			—			(5,870	)
Loss on early extinguishment of debt		(2,377	)		—			—			(2,377	)
Loss from equity investments		15,532			—			(15,532	)		—
Total other income (expense)		(10,161	)		—			(15,532	)		(25,693	)
Loss before provision for income taxes		32,783			24,182			(15,532	)		41,433
Deferred income tax expense		(6,172	)		(8,650	)		—			(14,822	)
Net income	$	26,611		$	15,532		$	(15,532	)	$	26,611

Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	356,597		$	30,962		$	—	$	387,559
Cash flows provided by (used in) investing activities:
Property acquisitions		(27,560	)		—			—		(27,560	)
Deposit for Nexen Acquisition		(7,040	)		—			—		(7,040	)
Exploration and development expenditures		(284,073	)		(37,967	)		—		(322,040	)
Other property and equipment additions		(2,016	)		—			—		(2,016	)
Proceeds from sale of assets		45,312			7,005			—		52,317
Net cash used in investing activities		(275,377	)		(30,962	)		—		(306,339	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		(65,000	)		—			—		(65,000	)
Deferred financing costs		(674	)		—			—		(674	)
Purchase of shares into treasury		(9,640	)		—			—		(9,640	)
Exercise of stock options		1,385			—			—		1,385
Net cash used in financing activities		(73,929	)		—			—		(73,929	)
Net decrease in cash and cash equivalents		7,291			—			—		7,291
Cash and cash equivalents at beginning of period		1,521			—			—		1,521
Cash and cash equivalents at end of period	$	8,812		$	—		$	—	$	8,812

Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	190,851		$	23,020		$	—	$	213,871
Cash flows provided by (used in) investing activities:
Property acquisitions		(575,372	)		(3,000	)		—		(578,372	)
Exploration and development expenditures		(165,308	)		(19,542	)		—		(184,850	)
Other property and equipment additions		(1,265	)		(478	)		—		(1,743	)
Net cash used in investing activities		(741,945	)		(23,020	)		—		(764,965	)
Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		509,313			—			—		509,313
Repayments of indebtedness		(20,000	)		—			—		(20,000	)
Deferred financing costs		(8,469	)		—			—		(8,469	)
Purchase of shares into treasury		(8,798	)		—			—		(8,798	)
Exercise of stock options		441			—			—		441
Net cash provided by financing activities		472,487			—			—		472,487
Net increase in cash and cash equivalents		(78,607	)		—			—		(78,607	)
Cash and cash equivalents at beginning of period		80,128			—			—		80,128
Cash and cash equivalents at end of period	$	1,521		$	—		$	—	$	1,521

Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	136,245		$	35,007		$	—	$	171,252
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		2,466			—			—		2,466
Property acquisitions		(235,486	)		—			—		(235,486	)
Exploration and development expenditures		(40,996	)		(35,007	)		—		(76,003	)
Other property and equipment additions		(1,568	)		—			—		(1,568	)
Net cash used in investing activities		(275,584	)		(35,007	)		—		(310,591	)
Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		203,794			—			—		203,794
Deferred financing costs		(6,646	)		—			—		(6,646	)
Purchase of shares into treasury		(11,353	)		—			—		(11,353	)
Exercise of stock options		119			—			—		119
Net cash provided by financing activities		185,914			—			—		185,914
Net increase in cash and cash equivalents		46,575			—			—		46,575
Cash and cash equivalents at beginning of period		33,553			—			—		33,553
Cash and cash equivalents at end of period	$	80,128		$	—		$	—	$	80,128

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(In thousands, except share data)

	March 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	4,448		$	8,812
Trade accounts receivable – net		87,484			70,707
Fair value of commodity derivative instruments		55			501
Deferred tax asset		7,852			8,949
Prepaid expenses		4,979			6,868
Total current assets		104,818			95,837
Property and equipment, at cost under the successful efforts method of accounting		2,575,959			2,355,219
Less accumulated depreciation, depletion, amortization and impairments		(664,470	)		(618,788	)
Net property and equipment		1,911,489			1,736,431
Deposit for Nexen Acquisition		—			7,040
Restricted cash		6,023			6,023
Fair value of commodity derivative instruments		160			238
Deferred financing costs - net of accumulated amortization of $6,312 and $5,549 at March 31, 2014 and December 31, 2013, respectively		9,513			10,106
Other assets		1,433			2,156
Total assets	$	2,033,436		$	1,857,831
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	86,658		$	59,431
Accrued expenses		157,883			131,125
Asset retirement obligations		46,076			51,601
Fair value of commodity derivative instruments		26,177			29,636
Total current liabilities		316,794			271,793
Long-term debt		718,000			627,355
Asset retirement obligations		223,180			203,849
Deferred tax liabilities		129,344			122,812
Fair value of commodity derivative instruments		1,326			2,136
Other		821			673
Total liabilities		1,389,465			1,228,618
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively		—			—
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; shares issued: 41,118,523 and 40,970,137 at March 31, 2014 and December 31, 2013, respectively; shares outstanding: 39,206,958 and 39,097,394 at March 31, 2014 and December 31, 2013, respectively		41			41
Additional paid-in capital		521,566			519,114
Treasury stock, at cost, 1,911,565 and 1,872,743 shares at March 31, 2014 and December 31, 2013, respectively		(32,182	)		(31,157	)
Retained earnings		154,546			141,215
Total stockholders’ equity		643,971			629,213
Total liabilities and stockholders' equity	$	2,033,436		$	1,857,831

See accompanying notes to condensed consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands, except share data)

	Three Months Ended March 31,
	2014			2013
Revenue:
Oil and natural gas	$	158,470		$	180,984
Other		1,021			1,365
Total revenue		159,491			182,349
Costs and expenses:
Lease operating		41,734			41,579
Transportation		900			650
Exploration expenditures and dry hole costs		4,941			1,933
Depreciation, depletion and amortization		45,645			46,522
Accretion of liability for asset retirement obligations		6,997			6,032
General and administrative		10,287			7,092
Taxes, other than on earnings		2,472			2,860
Other		(881	)		2,989
Total costs and expenses		112,095			109,657
Income from operations		47,396			72,692
Other income (expense):
Interest income		10			10
Interest expense		(13,304	)		(13,095	)
Loss on derivative instruments		(13,142	)		(13,951	)
Total other expense		(26,436	)		(27,036	)
Income before income taxes		20,960			45,656
Deferred income tax expense		(7,629	)		(16,619	)
Net income		13,331			29,037
Basic earnings per share	$	0.34		$	0.74
Diluted earnings per share	$	0.34		$	0.73
Weighted average common shares used in computing earnings per share:
Basic		38,714			38,823
Diluted		39,233			39,204

See accompanying notes to condensed consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	13,331		$	29,037
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization		45,645			46,522
Accretion of liability for asset retirement obligations		6,997			6,032
Change in fair value of derivative instruments		(3,746	)		7,383
Non-cash compensation		2,425			1,612
Deferred income taxes		7,629			16,519
Amortization of deferred financing costs and discount on debt		1,408			1,318
Other		(802	)		2,915
Changes in operating assets and liabilities:
Trade accounts receivable		(16,777	)		(6,473	)
Prepaid expenses		1,889			1,667
Other assets		724			210
Accounts payable and accrued expenses		19,264			(21,361	)
Asset retirement obligation settlements		(15,047	)		(7,139	)
Net cash provided by operating activities		62,940			78,242
Cash flows provided by (used in) investing activities:
Property acquisitions		(57,934	)		(2,210	)
Exploration and development expenditures		(98,969	)		(63,577	)
Other property and equipment additions		(231	)		(485	)
Net cash used in investing activities		(157,134	)		(66,272	)
Cash flows provided by (used in) financing activities:
Proceeds from (repayments of) indebtedness		90,000			(10,000	)
Deferred financing costs		(170	)		(405	)
Exercise of stock options		—			239
Net cash provided by (used in) financing activities		89,830			(10,166	)
Net increase (decrease) in cash and cash equivalents		(4,364	)		1,804
Cash and cash equivalents at beginning of period		8,812			1,521
Cash and cash equivalents at end of period	$	4,448		$	3,325

See accompanying notes to condensed consolidated financial statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) Basis of Presentation

The financial information as of March 31, 2014 and for the three-month periods ended March 31, 2014 and March 31, 2013 has not been audited. However, in the opinion of management, all adjustments (which include only normal, recurring adjustments) necessary to present fairly the financial position and results of operations for the periods presented have been included therein. Certain information and footnote disclosures normally in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to rules and regulations of the Securities and Exchange Commission. The condensed consolidated balance sheet at December 31, 2013 has been derived from the audited financial statements at that date. These financial statements and footnotes should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Annual Report”). The results of operations and cash flows for the first three months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

Recent Events. On March 12, 2014, we entered into an Agreement and Plan of Merger (as amended, the “Merger Agreement”) with Energy XXI (Bermuda) Limited (“EXXI”) and two of its subsidiaries, pursuant to which EXXI will acquire all of our outstanding shares of common stock for total consideration of $2.3 billion, including the assumption of debt (the “Merger”). Upon the completion of the Merger, we will become an indirect wholly owned subsidiary of EXXI. The consideration to be received by our stockholders is valued at $39.00 per share of our stock based on the closing price of EXXI’s common stock as of March 11, 2014. The aggregate consideration will be paid approximately 65 percent in cash and approximately 35 percent in EXXI common shares, based on the closing price of EXXI’s common stock as of March 11, 2014. Our stockholders will be able to elect to receive, for each share of our stock held, either (i) $39.00 in cash, (ii) 1.669 shares of EXXI common stock, or (iii) $25.35 in cash plus 0.584 shares of EXXI common stock. All elections by stockholders will be subject to proration with respect to the stock and the cash portion so that approximately 65% of the aggregate merger consideration is paid in cash and approximately 35% is paid in shares of EXXI common stock. Upon closing, EXXI shareholders are expected to own approximately 75 percent of the combined company and EPL shareholders are expected to own the remaining 25 percent.

On April 14, 2014, we announced we will hold a special meeting of our stockholders on May 30, 2014 to vote on the proposed Merger. The Merger is expected to close in the second quarter of 2014 and is subject to shareholder approval by both companies and other customary closing conditions.

(2) Acquisitions and Dispositions

The Nexen Acquisition

On January 15, 2014, we acquired from Nexen Petroleum Offshore U.S.A., Inc. (“Nexen”) a 100% working interest of certain shallow-water central Gulf of Mexico shelf oil and natural gas assets for $70.4 million, subject to customary adjustments to reflect the September 1, 2013, economic effective date (the “Nexen Acquisition”). The assets we acquired comprise five leases in the Eugene Island 258/259 field (the “EI Interests”). Estimated proved reserves as of the September 1, 2013 effective date consisted of approximately 2.6 Mmboe of proved developed producing reserves, about 91% of which was oil.

The Nexen Acquisition was financed with borrowings under our Senior Credit Facility. In January 2014, our lenders approved a $50.0 million increase in our borrowing base under our Senior Credit Facility, increasing our borrowing base to $475.0 million. See Note 5, “Indebtedness” for more information regarding our Senior Credit Facility.

The following allocation of the purchase price is preliminary and includes estimates. This preliminary allocation is based on information that was available to management at the time these condensed consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas. Management has not yet had the opportunity to complete its assessment of fair values of the assets acquired and liabilities assumed. In addition, the purchase price could change materially as management finalizes adjustments to purchase price provided for by the purchase and sale agreement. Accordingly, the allocation may change materially as additional information becomes available and is assessed by management.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects management’s estimate of customary adjustments to purchase price provided for by the purchase and sale agreement of approximately $7.2 million to reflect an economic effective date of September 1, 2013.

(In thousands)	September 1, 2013
Oil and natural gas properties	$	81,330
Asset retirement obligations		(18,097	)
Net assets acquired	$	63,233

The West Delta 29 Acquisition

On September 26, 2013, we acquired from W&T Offshore, Inc. (“W&T”) an asset package consisting of certain Gulf of Mexico shelf oil and natural gas interests in the West Delta 29 field (the “WD29 Interests”) for $21.8 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2013 (the “WD29 Acquisition”). We estimate that the proved reserves as of the January 1, 2013 economic effective date totaled approximately 0.7 Mmboe, of which 95% were oil and 58% were proved developed reserves. The WD29 Acquisition was funded with a portion of the proceeds from the sale of certain shallow water Gulf of Mexico shelf oil and natural gas interests located within the non-operated Bay Marchand field in a tax-deferred exchange of properties.

(In thousands)	January 1, 2013
Oil and natural gas properties	$	16,515
Asset retirement obligations		(1,398	)
Net assets acquired	$	15,117

Results of Operations and Pro Forma Information

Revenues and lease operating expenses attributable to acquired interests and properties were as follows:

	Three Months Ended March 31, 2014
	(In thousands)
EI Interests:
Revenues	$	8,380
Lease operating expenses	$	3,656
WD29 Interests:
Revenues	$	3,232
Lease operating expenses	$	59

The following supplemental pro forma information presents consolidated results of operations as if the Nexen Acquisition and WD29 Acquisition had occurred on January 1, 2013. The supplemental unaudited pro forma information was derived from a) our historical condensed consolidated statements of operations, b) the statements of revenues and direct operating expenses of the EI Interests and c) the statements of revenues and direct operating expenses of the WD29 Interests, which were derived from our historical accounting records. This information does not purport to be indicative of results of operations that would have occurred had the acquisitions occurred on January 1, 2013, nor is such information indicative of any expected future results of operations.

	Pro Forma Three Months Ended March 31,
(in thousands, except per share data)	2014		2013
Revenue	$	160,561	$	199,488
Net Income	$	13,372	$	34,129
Basic Earnings per share	$	0.34	$	0.87
Diluted Earnings per share	$	0.34	$	0.86

(3) Earnings Per Share

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

	Three Months Ended March 31,
	2014			2013
	(in thousands, except per share data)
Income (numerator):
Net income	$	13,331		$	29,037
Net income attributable to participating securities		(166	)		(290	)
Net income attributable to common shares	$	13,165		$	28,747
Weighted average shares (denominator):
Weighted average shares—basic		38,714			38,823
Dilutive effect of stock options		519			381
Weighted average shares—diluted		39,233			39,204
Basic earnings per share	$	0.34		$	0.74
Diluted earnings per share	$	0.34		$	0.73

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Weighted average shares		497		167

(4) Asset Retirement Obligations

The following table reconciles the beginning and ending aggregate recorded amount of our asset retirement obligations.

	Three Months Ended March 31, 2014
	(in thousands)
Beginning of period total	$	255,450
Accretion expense		6,997
Liabilities assumed in acquisitions		18,097
Revisions		3,759
Liabilities settled		(15,047	)
End of period total		269,256
Less: End of period, current portion		46,076
End of period, noncurrent portion	$	223,180

(5) Indebtedness

The following table sets forth our indebtedness.

	March 31, 2014		December 31, 2013
	(In thousands)
8.25% senior notes issued February 14, 2011 and October 25, 2012, face amount of $510.0 million, interest rate of 8.25% payable semi-annually, in arrears on February 15 and August 15 of each year, maturity date February 15, 2018	$	498,000	$	497,355
Senior Credit Facility, interest rate based on base rate or LIBOR plus a floating spread, maturity date October 31, 2016		220,000		130,000
Total indebtedness		718,000		627,355
Current portion of indebtedness		—		—
Noncurrent portion of indebtedness	$	718,000	$	627,355

8.25% Senior Notes

The 8.25% senior notes consist of $510.0 million in aggregate principal amount of our 8.25% senior notes due 2018 (the “8.25% Senior Notes”) issued under an Indenture dated February 14, 2011 (as amended and supplemented, the “2011 Indenture”). The 8.25% Senior Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest due semi-annually, in arrears, on February 15th and August 15th of each year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. The effective interest rate on the 8.25% Senior Notes is approximately 9.1%. For additional information regarding the 8.25% Senior Notes, see Note 7, “Indebtedness,” of our 2013 Annual Report.

On April 7, 2014, EXXI solicited consents (the “Consent Solicitation”) from the holders of our 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the 2011 Indenture (the “COC Amendments”). Under the COC Amendments, the Merger will not be treated as a “change of control” for purposes of the 101% change of control put contained in the 2011 Indenture. The Consent Solicitation was made by EXXI as permitted by the Merger Agreement. The COC Amendments will cease to be operative if the Merger is not consummated or if the consent fee is not paid by EXXI. If the Merger is consummated, EXXI will be obligated to pay an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the COC Amendments are validly delivered and unrevoked to the paying agent for the Consent Solicitation on behalf of the holders who delivered such valid and unrevoked consents to the COC Amendments on or prior to 5:00 p.m. New York City time on April 17, 2014. We have no obligations to pay all or any portion of the consent fee. On April 18, 2014, we entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among us, the guarantors party thereto, and U.S. Bank National Association, as trustee. We entered into the Supplemental Indenture after the receipt of consents from the requisite holders of the 8.25% Senior Notes in accordance with the terms and conditions of the Consent Solicitation.

Senior Credit Facility

(6) Derivative Instruments and Hedging Activities

We enter into derivative instruments to reduce exposure to fluctuations in the price of oil and natural gas for a portion of our production. Our fixed-price swaps fix the sales price for a limited amount of our production and, for the contracted volumes, eliminate our ability to benefit from increases in the sales price of the production. Derivative instruments are carried at their fair value on the condensed consolidated balance sheets as Fair value of commodity derivative instruments and all gains and losses due to changes in fair market value and contract settlements are recorded in Gain (loss) on derivative instruments in Other income (expense) in the condensed consolidated statements of operations. See Note 7 for information regarding fair values of our derivative instruments.

The following tables set forth our derivative instruments outstanding as of March 31, 2014.

Oil Contracts

	Fixed-Price Swaps
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbls)
April 2014		15,350		460,500		94.27
May 2014		15,350		475,850		94.27
June 2014		15,350		460,500		94.27
July 2014		14,350		444,850		93.56
August 2014		8,750		271,250		94.28
September 2014		8,750		262,500		94.28
October 2014		8,750		271,250		94.28
November 2014		8,750		262,500		94.28
December 2014		11,700		362,700		91.90
2014 Total		11,898		3,271,900		93.91

January 2015 - December 2015		1,500		547,500		97.70

Gas Contracts

	Fixed-Price Swaps
Remaining Contract Term	Daily Average Volume (Mmbtu)		Volume (Mmbtu)		Average Swap Price ($/Mmbtu)
April 2014 - December 2014		5,000		1,375,000		4.01
January 2015 - December 2015		4,300		1,569,500		4.31

The following table presents information about the components of loss on derivative instruments.

	Three Months Ended March 31,
	2014			2013
	(in thousands)
Change in fair market value	$	3,746		$	(7,383	)
Loss on settlement		(16,888	)		(6,568	)
Total loss on derivative instruments	$	(13,142	)	$	(13,951	)

(7) Fair Value Measurements

As of March 31, 2014 and December 31, 2013, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, primarily our commodity derivative instruments. The fair values of derivative instruments were measured using price inputs published by NYMEX and IntercontinentalExchange, Inc., or ICE. These price inputs are quoted prices for assets and liabilities similar to those held by us and meet the definition of Level 2 inputs within the fair value hierarchy.

Our commodity derivative instruments are subject to the terms of agreements with each of our counterparties that provide for the liquidation and settlement of all transactions with that counterparty in the event of default or termination. Our counterparties under these agreements are participants in our Senior Credit Facility. Although our derivative instruments are subject to enforceable set-off arrangements, we do not elect to offset amounts reported in our condensed consolidated balance sheet.

The following table presents the fair values of our commodity derivative instruments at their gross amounts and reflects the impact of our set-off arrangements which qualify for net presentation.

	March 31, 2014			December 31, 2013
	(in thousands)
Assets:
Current	$	55		$	501
Noncurrent		160			238
Total gross fair value		215			739
Less: counterparty set-off		(215	)		(739	)
Total net fair value		—			—

	March 31, 2014			December 31, 2013
	(in thousands)
Liabilities:
Current	$	26,177		$	29,636
Noncurrent		1,326			2,136
Total gross fair value		27,503			31,772
Less: counterparty set-off		(215	)		(739	)
Total net fair value		27,288			31,033

The carrying values reported in the condensed consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short term maturities of these instruments. The fair value for the 8.25% Senior Notes is based on quoted prices, which are Level 1 inputs within the fair value hierarchy. The carrying value of the Senior Credit Facility approximates its fair value because the interest rates are variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

The following table sets forth the carrying values and estimated fair values of our long-term indebtedness.

	March 31, 2014				December 31, 2013
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% Senior Notes	$	498,000	$	552,075	$	497,355	$	546,338
Senior Credit Facility		220,000		220,000		130,000		130,000
Total	$	718,000	$	772,075	$	627,355	$	676,338

(8) Commitments and Contingencies

On March 21, 2014, we were the high bidder on 21 leases at the Central Gulf of Mexico Lease Sale 231. The 21 high bid lease blocks cover a total of 92,030 acres on a gross and net basis and are all located in the shallow Gulf of Mexico within our core area of operations. Our share of the high bids totaled approximately $8.2 million, of which $1.6 million, was paid in March 2014.

We maintain restricted escrow funds in a trust for future abandonment costs at our East Bay property. The trust was originally funded with $15.0 million and, with accumulated interest, increased to $16.7 million at December 31, 2008. We may draw from the trust upon completion of qualifying abandonment activities at our East Bay field. At March 31, 2014, we had $6.0 million remaining in restricted escrow funds for decommissioning work in our East Bay field, which will remain restricted until substantially all required decommissioning in the East Bay field is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our condensed consolidated balance sheets.

On March 19, 2014, an alleged stockholder filed a class action lawsuit on behalf of our stockholders against our Company, our directors, and EXXI, as defendants. The lawsuit is styled Antonio Lopez v. EPL Oil & Gas, Inc., et al., C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware. On April 14, 2014, another alleged stockholder filed a class action lawsuit on behalf of our stockholders against our Company, our directors, and EXXI, as defendants. This lawsuit is styled David Lewandoski v. EPL Oil & Gas, Inc., et al., C.A. No. 9533-VCN, in the Court of Chancery of the State of Delaware. On April 23, 2014, a third alleged stockholder filed a class action lawsuit on behalf of our stockholders against our Company, our directors, and EXXI, as defendants. This lawsuit is styled Roberta Feinstein v. EPL Oil & Gas, Inc., et al., C.A. No. 9570-VCN, in the Court of Chancery of the State of Delaware. The foregoing lawsuits were consolidated by the Court of Chancery of the State of Delaware on May 5, 2014. The consolidated lawsuit is styled In re EPL Oil & Gas, Inc. Stockholders Litigation, Consol. C.A. No. 9460-VCN and is referred to herein as the “Delaware Action.” The Lopez complaint, which was amended on April 15, 2014, was deemed the operative complaint in the Delaware Action.

Plaintiffs in the Delaware Action allege a variety of causes of action challenging the Merger, including that (a) our directors have allegedly breached fiduciary duties in connection with the Merger and (b) EXXI has allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on allegations that (i) the Merger allegedly provides inadequate consideration to our stockholders for their shares of our common stock; (ii) the Merger Agreement contains contractual terms that will allegedly dissuade other potential acquirers from making competing offers for shares of our common stock; (iii) certain of our officers and directors are allegedly receiving benefits—including (A) an offer for one of our directors to join the EXXI board of directors and (B) the triggering of change-in-control provisions in notes held by our executive officers—that are not equally shared by our stockholders; (iv) EXXI required our officers and directors to agree to vote their shares of our common stock in favor of the Merger; (v) we provided, and EXXI obtained, non-public information that allegedly allowed EXXI to acquire us for inadequate consideration; and (vi) the Registration Statement contains inadequate disclosures regarding the Merger.

Based on these allegations, plaintiffs in the Delaware Action seek to enjoin the defendants from proceeding with or consummating the Merger. To the extent that the Merger is consummated, plaintiffs seek to have the Merger Agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

To date, the defendants have not yet answered or filed responsive motions to the Delaware Action, other than to oppose plaintiffs’ motion to expedite the proceedings. We cannot predict the outcome of the Delaware Action or any other lawsuits challenging the Merger that might be filed subsequent to the date of the filing of this quarterly report; nor can we predict the amount of time and expense that will be required to resolve the Delaware Action. We intend to vigorously defend the Delaware Action.

We are a defendant in a number of other lawsuits and are involved in governmental and regulatory proceedings, all of which arose in the ordinary course of business, including, but not limited to, personal injury claims, royalty claims, contract claims, and environmental claims, including claims involving assets owned by acquired companies. While the ultimate outcome and impact on us cannot be predicted with certainty, management believes that the resolution of pending proceedings will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

(9) Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 5, all of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries) each of which is 100% owned by EPL Oil & Gas, Inc. (the “Guarantor Subsidiaries”), jointly and severally guaranteed the payment obligations under our 8.25% Senior Notes. The guarantees are full and unconditional, as those terms are used in Rule 3-10 of Regulation S-X, except that a Guarantor Subsidiary can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2011 Indenture. So long as other applicable provisions of the indenture are adhered to, these customary circumstances include: when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, or when the Guarantor Subsidiary is sold or sells all of its assets. The following supplemental financial information sets forth, on a consolidating basis, the balance sheets, statements of operations and cash flow information for EPL Oil & Gas, Inc. (Parent Company Only) and for the Guarantor Subsidiaries. We have not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries, or for any individual Guarantor Subsidiary, because management has determined that such information is not material to investors.

Supplemental Condensed Consolidating Balance Sheet
As of March 31, 2014

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,448		$	—		$	—		$	4,448
Trade accounts receivable – net		87,349			135			—			87,484
Intercompany receivables		34,788			—			(34,788	)		—
Fair value of commodity derivative instruments		55			—			—			55
Deferred tax asset		7,852			—			—			7,852
Prepaid expenses		4,979			—			—			4,979
Total current assets		139,471			135			(34,788	)		104,818
Property and equipment		2,260,701			315,258			—			2,575,959
Less accumulated depreciation, depletion, amortization and impairments		(567,498	)		(96,972	)		—			(664,470	)
Net property and equipment		1,693,203			218,286			—			1,911,489
Investment in affiliates		124,581			—			(124,581	)		—
Restricted cash		6,023			—			—			6,023
Fair value of commodity derivative instruments		160			—			—			160
Deferred financing costs		9,513			—			—			9,513
Other assets		1,343			90			—			1,433
Total assets	$	1,974,294		$	218,511		$	(159,369	)	$	2,033,436
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		85,960			698			—			86,658
Intercompany payables		—			34,788			(34,788	)		—
Accrued expenses		157,868			15			—			157,883
Asset retirement obligations		46,076			—			—			46,076
Fair value of commodity derivative instruments		26,177			—			—			26,177
Total current liabilities		316,081			35,501			(34,788	)		316,794
Long-term debt		718,000			—			—			718,000
Asset retirement obligations		178,995			44,185			—			223,180
Deferred tax liabilities		115,100			14,244			—			129,344
Fair value of commodity derivative instruments		1,326			—			—			1,326
Other		821			—			—			821
Total liabilities		1,330,323			93,930			(34,788	)		1,389,465
Stockholders’ equity:
Preferred stock		—			—			—			—
Common stock		41			—			—			41
Additional paid-in capital		521,566			85,479			(85,479	)		521,566
Treasury stock, at cost		(32,182	)		—			—			(32,182	)
Retained earnings		154,546			39,102			(39,102	)		154,546
Total stockholders’ equity		643,971			124,581			(124,581	)		643,971
Total liabilities and stockholders' equity	$	1,974,294		$	218,511		$	(159,369	)	$	2,033,436

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2013

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	8,812		$	—		$	—		$	8,812
Trade accounts receivable - net		70,520			187			—			70,707
Intercompany receivables		39,085			—			(39,085	)		—
Fair value of commodity derivative instruments		501			—						501
Deferred tax asset		8,949			—			—			8,949
Prepaid expenses		6,868			—						6,868
Total current assets		134,735			187			(39,085	)		95,837
Property and equipment		2,041,689			313,530			—			2,355,219
Less accumulated depreciation, depletion, amortization and impairments		(526,736	)		(92,052	)		—			(618,788	)
Net property and equipment		1,514,953			221,478			—			1,736,431
Investment in affiliates		122,697			—			(122,697	)		—
Deposit for Nexen Acquisition		7,040			—			—			7,040
Restricted cash		6,023			—			—			6,023
Fair value of commodity derivative instruments		238			—			—			238
Deferred financing costs		10,106			—			—			10,106
Other assets		2,067			89			—			2,156
Total assets	$	1,797,859		$	221,754		$	(161,782	)	$	1,857,831
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	58,758		$	673		$	—		$	59,431
Intercompany payables		—			39,085			(39,085	)		—
Accrued expenses		131,111			14			—			131,125
Asset retirement obligations		51,601			—			—			51,601
Fair value of commodity derivative instruments		29,636			—			—			29,636
Total current liabilities		271,106			39,772			(39,085	)		271,793
Long-term debt		627,355			—			—			627,355
Asset retirement obligations		160,466			43,383			—			203,849
Deferred tax liabilities		106,910			15,902			—			122,812
Fair value of commodity derivative instruments		2,136			—			—			2,136
Other		673									673
Total liabilities		1,168,646			99,057			(39,085	)		1,228,618
Stockholders’ equity:
Preferred stock		—			—			—			—
Common stock		41			—			—			41
Additional paid-in capital		519,114			85,479			(85,479	)		519,114
Treasury stock		(31,157	)		—			—			(31,157	)
Retained earnings		141,215			37,218			(37,218	)		141,215
Total stockholders’ equity		629,213			122,697			(122,697	)		629,213
Total liabilities and stockholders' equity	$	1,797,859		$	221,754		$	(161,782	)	$	1,857,831

Supplemental Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2014

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	141,812		$	16,658		$	—		$	158,470
Other		264			757			—			1,021
Total revenue		142,076			17,415			—			159,491
Costs and expenses:
Lease operating		35,736			5,998			—			41,734
Transportation		899			1			—			900
Exploration expenditures and dry hole costs		4,941			—			—			4,941
Depreciation, depletion and amortization		40,696			4,949			—			45,645
Accretion of liability for asset retirement obligations		5,788			1,209			—			6,997
General and administrative		10,287			—			—			10,287
Taxes, other than on earnings		177			2,295			—			2,472
Other		(881	)		—			—			(881	)
Total costs and expenses		97,643			14,452			—			112,095
Income from operations		44,433			2,963			—			47,396
Other income (expense):
Interest income		10			—			—			10
Interest expense		(13,304	)		—			—			(13,304	)
Loss on derivative instruments		(13,142	)		—			—			(13,142	)
Income from equity investments		1,884			—			(1,884	)		—
Total other income (expense)		(24,552	)		—			(1,884	)		(26,436	)
Income before provision for income taxes		19,881			2,963			(1,884	)		20,960
Deferred income tax expense		(6,550	)		(1,079	)		—			(7,629	)
Net income	$	13,331		$	1,884		$	(1,884	)	$	13,331

Supplemental Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2013

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	159,067		$	21,917		$	—		$	180,984
Other		222			1,143			—			1,365
Total revenue		159,289			23,060			—			182,349
Costs and expenses:
Lease operating		34,822			6,757			—			41,579
Transportation		646			4			—			650
Exploration expenditures and dry hole costs		1,933			—			—			1,933
Depreciation, depletion and amortization		40,868			5,654			—			46,522
Accretion of liability for asset retirement obligations		4,924			1,108			—			6,032
General and administrative		7,092			—			—			7,092
Taxes, other than on earnings		285			2,575			—			2,860
Other		2,989			—			—			2,989
Total costs and expenses		93,559			16,098			—			109,657
Income from operations		65,730			6,962			—			72,692
Other income (expense):
Interest income		10			—			—			10
Interest expense		(13,095	)		—			—			(13,095	)
Loss on derivative instruments		(13,951	)		—			—			(13,951	)
Income from equity investments		4,428			—			(4,428	)		—
Total other income (expense)		(22,608	)		—			(4,428	)		(27,036	)
Income before provision for income taxes		43,122			6,962			(4,428	)		45,656
Deferred income tax expense		(14,085	)		(2,534	)		—			(16,619	)
Net income	$	29,037		$	4,428		$	(4,428	)	$	29,037

Supplemental Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2014

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	61,212		$	1,728		$	—	$	62,940
Cash flows provided by (used in) investing activities:
Property acquisitions		(57,934	)		—			—		(57,934	)
Exploration and development expenditures		(97,241	)		(1,728	)		—		(98,969	)
Other property and equipment additions		(231	)		—			—		(231	)
Net cash used in investing activities		(155,406	)		(1,728	)		—		(157,134	)
Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		90,000			—			—		90,000
Deferred financing costs		(170	)		—			—		(170	)
Net cash used in financing activities		89,830			—			—		89,830
Net decrease in cash and cash equivalents		(4,364	)		—			—		(4,364	)
Cash and cash equivalents at beginning of period		8,812			—			—		8,812
Cash and cash equivalents at end of period	$	4,448		$	—		$	—	$	4,448

Supplemental Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2013

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	75,475		$	2,767		$	—	$	78,242
Cash flows provided by (used in) investing activities:
Property acquisitions		(2,210	)		—			—		(2,210	)
Exploration and development expenditures		(60,810	)		(2,767	)		—		(63,577	)
Other property and equipment additions		(485	)		—			—		(485	)
Net cash used in investing activities		(63,505	)		(2,767	)		—		(66,272	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		(10,000	)		—			—		(10,000	)
Deferred financing costs		(405	)		—			—		(405	)
Exercise of stock options		239			—			—		239
Net cash provided by financing activities		(10,166	)		—			—		(10,166	)
Net increase in cash and cash equivalents		1,804			—			—		1,804
Cash and cash equivalents at beginning of period		1,521			—			—		1,521
Cash and cash equivalents at end of period	$	3,325		$	—		$	—	$	3,325

Attached files

Energy XXI Ltd Reports

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