Epl Oil & Gas 10Q 2014 Q1 Quarterly report

Epl Oil & Gas Inactive 10-Q2014 Q1 Quarterly report

Content analysis

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

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

Commission file number: 001-16179

EPL Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)



Delaware	72-1409562
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)


919 Milam Street, Suite 1600, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 228-0711

Registrant’s telephone number, including area code

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐

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

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


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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐

As of May 2, 2014, there were 39,219,486 shares of the registrant’s common stock, par value $0.001 per share, outstanding.

TABLE OF CONTENTS


	Page

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements:

Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2014 and December 31, 2013	2

Condensed Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013	3

Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2014 and 2013	4

Notes to Condensed Consolidated Financial Statements (Unaudited)	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3. Quantitative and Qualitative Disclosures about Market Risk	25

Item 4. Controls and Procedures	26

PART II—OTHER INFORMATION

Item 1. Legal Proceedings	27

Item 1A. Risk Factors	27

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	29

Item 3. Defaults Upon Senior Securities	29

Item 4. Mine Safety Disclosures	29

Item 5. Other Information	29

Item 6. Exhibits	30

PART I—FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS.

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(In thousands, except share data)


	March 31,		December 31,
	2014		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 per 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

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.

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.

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	$	16,515
Asset retirement obligations		(1,398)
Net assets acquired	$	15,117

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 7, “Fair Value Measurements.”

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

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 $0.1 million related to the Nexen Acquisition, which were included in general and administrative expenses in the accompanying condensed consolidated statements of operations for the three months ended March 31, 2014.

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,
	2014		2013
(in thousands, except per share data)
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

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.

(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,		December 31,
	2014		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

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”). Our Senior Credit Facility is a revolving credit facility that can be used for revolving credit loans and letters of credit. The aggregate commitment under this facility is a maximum of $750.0 million and the maturity date is 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. In January 2014, our lenders approved a $50.0 million increase in our borrowing base to $475.0 million. As of March 31, 2014 and December 31, 2013, we had borrowings outstanding under the Senior Credit Facility of $220.0 million and $130.0 million, respectively. For additional information regarding our Senior Credit Facility, see Note 7, “Indebtedness,” of our 2013 Annual Report.

(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
	Daily Average				Average
	Volume		Volume		Swap Price
Remaining Contract Term	(Bbls)		(Bbls)		($/Bbl)
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
	Daily Average				Average
	Volume		Volume		Swap Price
Remaining Contract Term	(Mmbtu)		(Mmbtu)		($/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

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 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,		December 31,
	2014		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		-		-

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

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.

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.

(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.

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.

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.

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.

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 March 31, 2014


	Parent
	Company		Guarantor
	Only		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		Guarantor
	Only		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		Guarantor
	Only		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		Guarantor
	Only		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		Guarantor
	Only		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		Guarantor
	Only		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

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Statements we make in this Quarterly Report on Form 10-Q (the “Quarterly Report”) which express a belief, expectation or intention, as well as those that are not historical fact, may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors” in Items 1 and 1A of Part I of our 2013 Annual Report and under the heading “Risk Factors” in Item 1A of Part II of this Quarterly Report.

OVERVIEW

We were incorporated as a Delaware corporation in January 1998 and operate in a single segment as 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, which we consider our core area. We have focused on acquiring and developing assets in this region, as it offers a balanced and expansive array of existing and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations.

We maintain a website at www.eplweb.com that contains information about us, including links to our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all related amendments as soon as reasonably practicable after providing such reports to the Securities and Exchange Commission (the “SEC”).

We use the successful efforts method of accounting for oil and natural gas producing activities. Under this method, we capitalize lease acquisition costs, costs to drill and complete exploration wells in which proven reserves are discovered and costs to drill and complete development wells. Exploratory drilling costs are charged to expense if and when activities result in no reserves in commercial quantities. Seismic, geological and geophysical, and delay rental expenditures are expensed as they are incurred. We conduct various exploration and development activities jointly with others and, accordingly, recorded amounts for our oil and natural gas properties reflect only our proportionate interest in such activities. Our 2013 Annual Report includes a discussion of our critical accounting policies, which have not changed significantly since the end of the last fiscal year.

We produce both oil and natural gas. Throughout this Quarterly Report, when we refer to “total production,” “total reserves,” “percentage of production,” “percentage of reserves,” or any similar term, we have converted our natural gas reserves or production into barrel of oil equivalents. For this purpose, six thousand cubic feet of natural gas is equal to one barrel of oil, which is based on the relative energy content of natural gas and oil. Natural gas liquids are aggregated with oil in this Quarterly Report.

Recent Developments

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.

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 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.

Overview and Outlook

If the Merger is completed, then the future strategy of the Company will be determined by EXXI’s Board of Directors and management. As a result, this “Overview and Outlook” section addresses the Company’s current strategy, and it would be applicable only if the Merger Agreement is terminated without the occurrence of the Merger. Our fiscal year 2014 capital budget is $360 million, which is allocated to development activities and exploration projects within existing core fields. Additionally, we plan to spend approximately $50 million in 2014 on plugging, abandonment and other decommissioning activities. We budget our capital spending on exploration and development with the goal of remaining within cash flow from operations.

We continue to generate prospects, strive to maintain an extensive inventory of drillable prospects in-house and maintain exposure to new opportunities through relationships with industry partners. We continually review and monitor opportunities to acquire producing properties, leasehold acreage and drilling prospects so that we can act quickly as acquisition opportunities become available. We intend to focus our acquisition strategy on assets in the Gulf of Mexico and the Gulf Coast region that are characterized by production-weighted reserves, seismic coverage, operated positions and the ability to consolidate interests in existing properties. We intend to use acquisitions of this type as a key method to replace and grow reserves and production because we believe this strategy increases production and cash flow while reducing dry hole and exploration risk. We believe our expertise in the Gulf of Mexico shelf and in plugging and abandonment operations allows us to effectively evaluate acquisitions and to operate any properties we eventually acquire.

Our longer term operating strategy is to increase our oil and natural gas reserves and production while focusing on reducing exploration and development costs and operating costs to remain competitive with our offshore Gulf of Mexico industry peers.

We believe that our core competency in plugging, abandonment and decommissioning operations will enable us to achieve our objectives of prudently removing idle infrastructure throughout the remaining productive lives of our fields and, over time, to reduce ongoing lease operating expenses (“LOE”) associated with maintaining idle infrastructure.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as oil and natural gas prices, tropical weather, economic, political and regulatory developments and availability of other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil and natural gas could have a material adverse effect on our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. See “Risk Factors” in Part I, Item 1A of our 2013 Annual Report and Item 1A of Part II of this Quarterly Report for a more detailed discussion of these risks.

RESULTS OF OPERATIONS

The following table presents information about our oil and natural gas operations.


	Three Months Ended March 31,
	2014		2013
Net production (per day):
Oil (Bbls)		16,250		17,327
Natural gas (Mcf)		27,507		32,146
Total (Boe)		20,835		22,685
Average sales prices:
Oil (per Bbl)	$	99.56	$	109.30
Natural gas (per Mcf)		5.20		3.64
Total (per Boe)		84.51		88.65
Oil and natural gas revenues (in thousands):
Oil	$	145,605	$	170,448
Natural gas		12,865		10,536
Total		158,470		180,984
Impact of derivatives instruments settled during the period (1):
Oil (per Bbl)	$	(11.27)	$	(4.27)
Natural gas (per Mcf)		(0.17)		0.03
Average costs (per Boe):
LOE	$	22.26	$	20.37
Depreciation, depletion and amortization (“DD&A”)		24.34		22.79
Accretion of liability for asset retirement obligations		3.73		2.95
Taxes, other than on earnings		1.32		1.40
General and administrative (“G&A”) expenses		5.49		3.47
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil	$	(15,191)
Changes in production volumes of oil		(9,652)
Total decrease in oil sales		(24,843)
Changes in prices of natural gas	$	4,488
Changes in production volumes of natural gas		(2,159)
Total increase in natural gas sales		2,329

(1)See “—Other Income and Expense” section for further discussion of the impact of derivative instruments.

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Overview

During the three months ended March 31, 2014, we completed six development drilling operations, one exploratory drilling operation and three recompletion operations, all of which were successful.

Our operating results for the three months ended March 31, 2014, compared to the three months ended March 31, 2013, reflect a 6% decrease in oil production and a 14% decrease in natural gas production. Our product mix for the three months ended March 31, 2014 was 78% oil (including natural gas liquids) compared to 76% for the three months ended March 31, 2013.

Revenue and Net Income


	Three Months Ended March 31,
	2014		2013
	(in thousands)					$ Change	% Change
Oil and natural gas revenues	$	158,470	$	180,984	$	(22,514)	-12%
Net income		13,331		29,037		(15,706)	-54%

For the three months ended March 31, 2014, our oil and natural gas revenues decreased 12% as compared to the three months ended March 31, 2013, due primarily to a 9% decrease in average selling prices for our oil and the 6% decrease in oil production. The decrease in our oil revenues was partially offset by an increase in natural gas revenues, primarily due to a

43% increase in average selling prices for natural gas in the three months ended March 31, 2014, as compared to the three months ended March 31, 2013.

Our overall production volumes decreased by 8% for the three months ended March 31, 2014 when compared to the three months ended March 31, 2013. During the first two months of the quarter ended March 31, 2014, we experienced significant weather related downtime, which negatively impacted the average oil production for the quarter. Our Gulf of Mexico shelf production decreased 7% in the three months ended March 31, 2014, as compared to the three months ended March 31, 2013, due primarily to a decrease in production in our West Delta field, which was partially offset by an increase in production in our Ship Shoal 208 area and production from the recently acquired EI Interests. Production from the EI Interests increased our production rate by approximately 971 Boe per day for the quarter ended March 31, 2014, producing approximately 1,165 Boe per day since the acquisition date of January 15, 2014.

Our effective income tax rate for the three months ended March 31, 2014 and March 31, 2013 was 36.4%.

Operating Expenses

Our operating expenses primarily consist of the following:


	Three Months Ended March 31,
	2014		2013
	(in thousands)					$ Change	% Change
LOE	$	41,734	$	41,579	$	155	0%
Exploration expenditures and dry hole costs		4,941		1,933		3,008	156%
DD&A, including accretion expense		52,642		52,554		88	0%
G&A expenses		10,287		7,092		3,195	45%
Taxes, other than on earnings		2,472		2,860		(388)	-14%
Other		(881)		2,989		(3,870)	-129%

Exploration expenditures and dry hole costs increased for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013, primarily as a result of an increase in seismic expense and costs associated with the increased size of our geological and geophysical staff. Our seismic expense was $2.0 million and $0.5 million in the three months ended March 31, 2014 and 2013, respectively. Other exploratory expenses totaled approximately $2.9 million and $1.5 million in the three months ended March 31, 2014 and 2013, respectively.

G&A expenses increased for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013, primarily as a result of approximately $2.2 million of expenses incurred related to the Merger Agreement during the three months ended March 31, 2014. In addition, during the three months ended March 31, 2014, employee-related costs increased as compared to March 31, 2013, including an increase in non-cash share-based compensation.

Other operating expenses decreased for the three months ended March 31, 2014, as compared to the year ended March 31, 2013, primarily as a result of a decrease in loss on abandonment activities. During the three months ended March 31, 2014, we recorded a gain on abandonment activities of $0.9 million compared to the $3.0 million loss on abandonment activities recorded for the three months ended March 31, 2013.

Other Income and Expense

Interest expense remained relatively consistent for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013. For both periods, our interest expense includes interest on our 8.25% Senior Notes and borrowings on our Senior Credit Facility.

Other income (expense) in the three months ended March 31, 2014 includes a net loss on derivative instruments of $13.1 million consisting of a gain of $3.7 million due to the change in fair value of derivative instruments to be settled in the future and a loss of $16.9 million on derivative instruments settled during the quarter primarily from the impact of higher oil prices. Other income (expense) in the three months ended March 31, 2013 includes a net loss on derivative instruments of $14.0 million consisting of a loss of $7.4 million due to the change in fair value of derivative instruments to be settled in the future and a loss of $6.6 million on derivative instruments settled during the quarter primarily from the impact of higher oil prices.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Capital

As of May 2, 2014, we had $235.0 million available under our Senior Credit Facility, which has a borrowing base of $475.0 million. During January 2014, we borrowed $58.0 on our Senior Credit Facility to fund a portion of the Nexen Acquisition and we currently have $240.0 million outstanding under our Senior Credit Facility.

Our fiscal year 2014 capital budget is $360 million, which is allocated to development activities and exploration projects within existing core field areas. Additionally, we plan to spend approximately $50 million in 2014 on plugging, abandonment and other decommissioning activities. We intend to finance our capital budget with cash flow from operations. However, we may borrow under our Senior Credit Facility, as needed.

Cash Flow and Working Capital. Net cash provided by operating activities decreased to $62.9 million for the quarter ended March 31, 2014 compared to $78.2 million for the quarter ended March 31, 2013. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2014 capital expenditures with cash flow from operations and borrowings under our Senior Credit Facility, as needed.

Our revenue, profitability, cash flows and future growth are substantially dependent upon prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond our control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. Our derivative instruments serve to mitigate a portion of this price volatility on our cash flows. For the remainder of 2014, we have a total of 11,898 Bbls of oil per day hedged, all of which is hedged using Louisiana Light Sweet (“LLS”) fixed price swaps at a price averaging $93.91 per Bbl. We have a total of 5,000 Mmbtu of natural gas per day hedged for 2014, all of which is hedged using fixed price swaps at a price averaging $4.01 Mmbtu per day. In addition, we have begun hedging forecasted 2015 production with 1,500 Bbls of oil per day currently hedged using Brent fixed price swaps at a price of $97.70 per Bbl and 4,300 Mmbtu of natural gas per day currently hedged using fixed price swaps at a price averaging $4.31 Mmbtu per day.

We have incurred, and will continue to incur, capital expenditures to achieve production targets. While we expect to fund the majority of future capital expenditures with cash flow from operations, we depend on the availability of borrowings under our Senior Credit Facility as a source of liquidity, including for short-term working capital requirements. Based on anticipated oil and natural gas prices and availability under our Senior Credit Facility, we expect to be able to fund our planned capital expenditures budget, debt service requirements and working capital needs for 2014. In addition to borrowings under our Senior Credit Facility, in order to meet capital requirements, which could include the funding of future acquisitions, we may also have the ability to issue debt and equity securities under our universal shelf registration statement that became effective under the Securities Act in July 2011. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced. Any such extended decline could also have an adverse impact on our ability to issue additional debt or equity securities and our ability to comply with the financial covenants under our Senior Credit Facility, which in turn would limit further borrowings under our Senior Credit Facility.

At March 31, 2014, we had a working capital deficit of $212.0 million, compared to a deficit of $176.0 million at December 31, 2013. The increase in our working capital deficit as of March 31, 2014 is primarily due to increased accounts payable and accrued expenses related to exploration and development costs. The working capital deficit at December 31, 2013 was primarily due to the use of cash to repay borrowings under our Senior Credit Facility, which is classified as long-term debt, increased accounts payable and accrued expenses related to exploration and development costs, the increase in the current portion of our asset retirement obligations and an increase in the current liability associated with our derivative instruments. We have experienced, and expect to experience in the future, significant working capital deficits. Our working capital deficits have historically resulted from increased accounts payable and accrued expenses related to ongoing exploration and development costs, which may be capitalized as noncurrent assets, or increased investment in oil and natural gas properties. Additionally, we expect to use any available free cash flow to reduce our debt, all of which is long-term.

Capital Expenditures. During the quarter ended March 31, 2014, we incurred costs of approximately $132.7 million on development and exploration activities and a total of $2.0 million on seismic purchases. In addition, we spent approximately $15.0 million on plugging, abandonment and other decommissioning activities during the quarter ended March 31, 2014.

Acquisitions and Dispositions. On January 15, 2014, we completed the Nexen Acquisition for $70.4 million, which was financed with borrowings under our Senior Credit Facility. During 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.

We allocate capital in a rigorous and disciplined manner intended to achieve an overall lower risk capital expenditure profile that focuses on maximizing rate of return and requires projects to compete on that basis. This allocation has led us to

focus on oil-weighted projects, resulting in a trend of increasing oil production. From time to time, we may decide to divest of certain oil and gas properties that do not meet our capital expenditure risk, rate of return, operational control or other criteria.

Share Repurchase Program. 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 $80.0 million in July 2013. Under the program, we have repurchased 1,799,000 shares at an aggregate cash purchase price of approximately $29.7 million. We have not purchased any shares under the program during 2014. 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 SEC’s 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.

Restricted Cash. We maintain restricted escrow funds in a trust for future plugging, abandonment and other decommissioning costs at our East Bay field. As of March 31, 2014, we had $6.0 million remaining in restricted escrow funds in the trust 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.

8.25% Senior Notes. The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount issued under 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. For more information on our 8.25% Senior Notes, see Note 7, “Indebtedness,” of our 2013 Annual Report.

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”). Our Senior Credit Facility is a revolving credit facility that can be used for revolving credit loans and letters of credit. The aggregate commitment under this facility is a maximum of $750.0 million and the maturity date is 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. In January 2014, our lenders approved a $50.0 million increase in our borrowing base to $475.0 million. As of May 2, 2014, we had $240.0 million outstanding and $235.0 million in availability under our Senior Credit Facility. For additional information regarding our Senior Credit Facility, see Note 7, “Indebtedness,” of our 2013 Annual Report.

Analysis of Cash Flows —Three Months Ended March 31, 2014

The following table sets forth our cash flows:


	Three Months Ended March 31,
	2014		2013
	(In thousands)
Net cash provided by operating activities	$	62,940	$	78,242
Net cash used in investing activities		(157,134)		(66,272)
Net cash provided by (used in) financing activities		89,830		(10,166)

The decrease in our 2014 cash flows from operating activities primarily reflects decreases in revenues due to the decrease in oil prices and the decrease in our oil and natural gas production during the three months ended March 31, 2014, as compared to the three months ended March 31, 2013.

Net cash used in investing activities increased for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013, due to an increase in exploration and development expenditures in the three months ended March 31, 2014. In addition, net cash used in investing activities for the three months ended March 31, 2014, includes the cash used in the Nexen Acquisition of $57.9 million.

Net cash provided by financing activities during the three months ended March 31, 2014 reflects $90.0 million in borrowings under our Senior Credit Facility, of which we used approximately $57.9 million to fund the Nexen Acquisition and $32.1 million to meet working capital requirements. Net cash used in financing activities during the three months ended March 31, 2013 reflects repayments of $10.0 million of amounts borrowed under our Senior Credit Facility.

We have not paid any cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including our Senior Credit Facility and the 2011 Indenture governing the 8.25% Senior Notes, place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our board of directors.

New Accounting Pronouncements

None.

Cautionary Statement Concerning Forward Looking Statements

This Quarterly Report contains forward-looking statements within the meaning of, and we intend that such forward-looking statements be subject to the safe harbor provisions of, U.S. federal securities laws. Forward-looking statements are, by definition, statements that are not historical in nature and relate to possible future events. They may be, but are not necessarily, identified by words such as “will,” “would,” “should,” “likely,” “estimates,” “thinks,” “strives,” “may,” “anticipates,” “expects,” “believes,” “intends,” “goals,” “plans,” or “projects” and similar expressions.

These forward-looking statements reflect our current views with respect to possible future events, are based on various assumptions and are subject to risks and uncertainties. These forward-looking statements are not guarantees or predictions of our future performance, and our actual results and future developments may differ materially from those projected in, and contemplated by, the forward-looking statements. As a result, you should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the factors that could cause actual results to differ materially are the risks and uncertainties described under, “Risk Factors” in Item 1A of Part I of our 2013 Annual Report and Item 1A of Part II of this Quarterly Report, including the following:

•planned and unplanned capital expenditures;

•adequacy of capital resources and liquidity including, but not limited to, access to additional capacity under our Senior Credit Facility;

•volatility in oil and natural gas prices;

•volatility in the financial and credit markets;

•changes in general economic conditions;

•uncertainties in reserve and production estimates;

•replacing our oil and natural gas reserves;

•unanticipated recovery or production problems;

•availability, cost and adequacy of insurance coverage;

•hurricane and other weather-related interference with business operations;

•drilling and operating risks;

•production expense estimates;

•the impact of derivative positions;

•our ability to retain and motivate key executives and other necessary personnel;

•availability of drilling and production equipment and field service providers;

•the effects of delays in completion of, or shut-ins of, gas gathering systems, pipelines and processing facilities;

•potential costs associated with complying with new or modified regulations or interpretations of such regulations promulgated by the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement and the Pipeline and Hazardous Materials Administration of the U.S. Department of Transportation;

•the impact of political and regulatory developments;

•risks and liabilities associated with acquired properties or businesses;

•our ability to make and integrate acquisitions;

•our substantial level of indebtedness;

•our ability to incur additional indebtedness;

•oil and gas prices and competition;

cyber attacks;

•our ability to generate sufficient cash flow to meet our debt service and other obligations;

•the loss of key management in connection with the Merger;

•ability to complete the Merger in the anticipated timeframe or at all;

•business uncertainties and contractual restrictions while the Merger is pending; and

•expenses related to the Merger.

Many of these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

For a further list and description of various risks, relevant factors and uncertainties that could cause future results or events to differ materially from those expressed or implied in our forward-looking statements, see “Risk Factors” in Part 1, Item 1A of our 2013 Annual Report and elsewhere in our 2013 Annual Report and Part II, Item 1A of this Quarterly Report and elsewhere in this Quarterly Report; our reports and registration statements filed from time to time with the SEC; and other announcements we make from time to time. Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements.

Although we believe that the assumptions on which any forward-looking statements are based in this Quarterly Report and other periodic reports filed by us are reasonable when and as made, no assurance can be given that such assumptions will prove correct. All forward-looking statements in this Quarterly Report are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by applicable securities laws and regulations.

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view our ongoing market-risk exposure.

Interest Rate Risk

We are exposed to changes in interest rates which affect the interest earned on our interest-bearing deposits and the interest paid on borrowings under our Senior Credit Facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. At March 31, 2014 and December 31, 2013, we had $220.0 million and $130.0 million drawn under our Senior Credit Facility, respectively. Borrowings under our Senior Credit Facility bear interest ranging from a base rate plus a margin of 0.75% to 1.75% on base rate borrowings and LIBOR plus a margin of 1.75% to 2.75% on LIBOR borrowings. The maturity date of the Senior Credit Facility is October 31, 2016.

At March 31, 2014, our total indebtedness outstanding also includes $498.0 million (net of unamortized initial purchasers’ discount of $12.0 million) related to our fixed rate 8.25% Senior Notes. At March 31, 2014, the estimated fair value of our 8.25% Senior Notes was approximately $552.1 million.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our Senior Credit Facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.

We use commodity derivative instruments to reduce our exposure to commodity price risks associated with future oil and natural gas production and not for trading purposes. The tables below provide information about our derivative instruments that were outstanding as of March 31, 2014. For a description of assumptions related to our calculations of fair value, please see Note 7, “Fair Value Measurements,” of the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

Oil Contracts

Fixed-Price Swaps

Daily Average

Average

Volume

Swap Price

Fair Value

Remaining Contract Term

(Bbls)

($/Bbl)

(In thousands)

April 2014 - December 2014

11,898

3,271,900

93.91

(24,764)

January 2015 - December 2015

1,500

547,500

97.70

(2,070)

Gas Contracts

Fixed-Price Swaps

Daily Average

Average

Volume

Swap Price

Fair Value

Remaining Contract Term

(Mmbtu)

($/Mmbtu)

(In thousands)

April 2014 - December 2014

5,000

1,375,000

4.01

(614)

January 2015 - December 2015

4,300

1,569,500

4.31

160

The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new regulation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, required the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation. In July 2012 certain definitions were adopted by the SEC and the CFTC and based on those definitions, we believe we will qualify for the end-user exception related to the clearing requirement for swaps, but we are required to adhere to new reporting and recordkeeping requirements.

Item 4.CONTROLS AND PROCEDURES.

(a) Quarterly Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. This information is also accumulated and communicated to management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, under the supervision and with the

participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the most recent fiscal quarter reported on herein. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2014.

Because of their inherent limitations, disclosure controls and procedures may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that such controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the controls or procedures may deteriorate. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

(b) Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS.

For information regarding legal proceedings, see the information in Note 8, “Commitments and Contingencies” in the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report, which is incorporated by reference into Part II, Item 1 of this Quarterly Report.

Item 1A.RISK FACTORS.

In addition to the risk factors below and the other information set forth in this Form 10-Q, you should carefully consider the factors discussed in Part I, “Item 1A.—Risk Factors” in our 2013 Annual Report that could materially affect our business, financial condition or future results. The risks described in this Quarterly Report on Form 10-Q and in our 2013 Annual Report are not the only risks facing the Company. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may have a material adverse effect on our business, financial condition and future results.

The risk factors below are updates to the risk factors found under “Item 1A.—Risk Factors” in our 2013 Annual Report.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees, which could adversely affect our business and operations.

We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plan. Our success until the Merger is consummated will depend in part upon our ability to retain key management personnel and other key employees. Current and prospective employees may experience uncertainty about their roles within the combined company following the Merger, which may have an adverse effect on our ability to attract or retain key management and other key personnel.

Failure to complete the Merger, or delays in completing the Merger, could negatively impact our future business and financial results.

We cannot make any assurances that we will be able to satisfy all of the conditions to the Merger or succeed in any litigation brought in connection with the Merger. If the Merger is not completed, or there are delays in completing the Merger, our financial results may be adversely affected and we will be subject to several risks, including but not limited to:

being required to pay a termination fee of $45 million under certain circumstances provided in the Merger Agreement;

payment of the other party’s reasonable expenses relating to the Merger, such as legal, accounting, financial advisor and printing fees, in an amount not to exceed $6 million;

having had the focus of our management on the Merger instead of on pursuing other business opportunities that could have been beneficial to us; and

being subject to litigation related to any failure to complete the Merger.

If the Merger is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock price.

We are subject to business uncertainties and contractual restrictions while the Merger is pending, which could adversely affect our business and operations.

Under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the Merger, which may adversely affect our ability to execute certain of our business strategies, including the ability in certain cases to enter into contracts or incur capital expenditures to grow our business. Such limitations could negatively affect our businesses and operations, regardless of whether the Merger is completed. Furthermore, the process of planning to integrate two businesses and organizations for the post-merger period can divert management attention and company resources and could ultimately have an adverse effect on us.

In connection with the pending transaction, it is possible that some customers, suppliers and other persons with whom we have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with us as a result of the proposed merger, which could negatively affect our revenues, earnings and cash flows, as well as the market price of shares of our common stock, regardless of whether the transaction is completed.

The Merger Agreement contains provisions that limit our ability to pursue alternatives to the Merger transaction, could discourage a potential competing acquirer from making a favorable alternative transaction proposal and, in specified circumstances, could require us to pay a termination fee to the other party.

The Merger Agreement contains a “no solicitation” provision that, subject to limited exceptions, restricts our ability to initiate, solicit, facilitate, or knowingly encourage any inquiry or proposal in respect of a competing third-party proposal for the acquisition of our common stock or assets. In addition, we are generally required to negotiate in good faith with EXXI to modify the terms of the Merger Agreement in response to any competing acquisition proposals before our board of directors may withdraw or qualify its recommendation with respect to the Merger. In certain circumstances, upon termination of the Merger Agreement, a termination fee in the amount of $45 million will be required to be paid from one party to the other.

These provisions and other deal protection provisions in the Merger Agreement could discourage a potential third-party acquirer that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the Merger. These provisions might also result in a potential third-party acquirer proposing to pay a lower price to the stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

If the Merger Agreement is terminated and we decide to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Merger.

The risk factor below is an update to the risk factor titled “We may not be insured against all of the operating risks to which our business is exposed” found under “Item 1A.—Risk Factors” in our 2013 Annual Report.

We may not be insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, oil pollution, third party liability, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages and losses.

Currently, we have general liability insurance coverage with an annual aggregate limit of $2.0 million and umbrella excess liabilities coverage with an aggregate limit of $200.0 million applicable to our working interests. Our general liability policy is subject to a $25,000 per incident deductible. We also have an offshore property physical damage and operators extra expense policies that contain an aggregate of $200.1 million of named windstorm limit. Recoveries from these policies are subject to a $2.5 million deductible that applies to non-named windstorm occurrences and a $50.0 million deductible that applies to named windstorm events except for East Bay central facilities and rental compressor losses, which are subject to a 1.5% deductible of the scheduled values of the items making up a loss, but always subject to a $25,000 minimum. Further, there are sub-limits within the named windstorm annual aggregate limit for re-drill, non-blowout plugging and abandonment and excess removal of wreck. Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20 million to $75 million per occurrence. Deepwater wells have a coverage limit of $50 million per occurrence. Additionally, we maintain $150 million in oil pollution liability coverage as required under the Oil Pollution Act of 1990. Our control of well and oil pollution liability policy limits are scaled proportionately to our working interests, except for our deepwater control of well coverage, to which the $50 million limit applies to our working interest. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

An operational or hurricane related event may cause damage or liability in excess of our coverage, which might materially adversely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also materially adversely impact our financial position. For example, we experienced production interruptions in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance.

We regularly reevaluate the purchase of insurance, policy limits and terms. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

We maintain an Oil Spill Response Plan (the “Plan”) that defines our response requirements and procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans will generally be approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. We believe the Plan specifications are consistent with the requirements set forth by the BSEE.

The Company has contracted with an emergency and spill response management consultant, which would provide management expertise, personnel and equipment, under the supervision of the Company, in the event of an incident requiring a coordinated response. Additionally, the Company is a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico and has capabilities to simultaneously respond to multiple spills. CGA is structured to provide an effective method of staging response equipment and providing spill response for its member companies in the Gulf of Mexico. On January 1, 2013, CGA entered into an agreement with Clean Gulf Associates Services, LLC (“CGAS”), an affiliate of T&T Marine Salvage Inc. (“TTMS”). Through this agreement, CGAS will store, maintain, deploy and operate all CGA-owned equipment and provide response personnel. This agreement replaced the expiring Equipment Management, Contractor Services and Bareboat Charter Agreement that CGA had previously entered into with Marine Spill Response Corporation. CGAS maintains CGA’s equipment in various warehouse locations (currently including 50 skimmers with various estimated daily recovery capacities, numerous containment and storage systems including thousands of feet of boom and one fire boom system, tanks and storage barges, wildlife cleaning and rehabilitation facilities, and both aerial and vessel dispersant spray systems) at staging points around the Gulf of Mexico in its ready state. In the event of a spill, CGAS mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

Additional resources are available to the Company on an as-needed basis other than as a member of CGA, such as those of CGAS. CGAS has oil spill response equipment independent of, and in addition to, CGA’s equipment. CGAS’s equipment currently includes, according to CGAS’s website, skimmer, containment boom, pumps and lightering equipment, vacuum units and sorbents. In the event of a spill, CGAS activates contractors as necessary to provide additional resources or support services requested by its customers.

The response effectiveness, equipment and resources of these companies may change from time-to-time and current information is generally available on the websites of each of these organizations. There can be no assurances that the Company, together with the organizations described above will be able to effectively manage all emergency and/or spill response activities that may arise and any failures to do so may materially adversely impact the Company’s financial position, results of operations and cash flows.

Item 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None

Item 3.DEFAULTS UPON SENIOR SECURITIES.

None

Item 4.MINE SAFETY DISCLOSURES.

None

Item 5.OTHER INFORMATION.

None

EXHIBITS

Exhibit
Number

Exhibit Description

Incorporated by
Reference
Form

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

2.1

Agreement and Plan of Merger between EPL Oil & Gas, Inc., Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., and Clyde Merger Sub, Inc., dated as of March 12, 2014.

8-K

001-16179

2.1

3/13/2014

2.2

Amendment No. 1 to the Agreement and Plan of Merger between EPL Oil & Gas, Inc., Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., and Clyde Merger Sub, Inc., dated as of March 12, 2014.

10-K/A

001-16179

2.7

4/15/2014

3.1

Composite copy of the Third Amended and Restated Bylaws of EPL Oil & Gas, Inc., reflecting all amendments through March 11, 2014, the effective date of the Amendment to the Third Amended and Restated Bylaws.

4.1

Third Supplemental Indenture by and among EPL Oil & Gas, Inc., the other Guarantors named therein and U.S. Bank National Association, as Trustee, dated April 18, 2014.

8-K

001-16179

4.1

4/21/2014

10.1

Form of Energy XXI (Bermuda) Limited Voting Agreement, dated March 12, 2014.

8-K

001-16179

10.1

3/13/2014

10.2

Form of EPL Oil & Gas, Inc. Voting Agreement, dated March 12, 2014.

8-K

001-16179

10.2

3/13/2014

31.1

Certification of Principal Executive Officer of EPL Oil & Gas, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Principal Financial Officer of EPL Oil & Gas, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Section 1350 Certification of Principal Executive Officer of EPL Oil & Gas, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Section 1350 Certification of Principal Financial Officer of EPL Oil & Gas, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

* Incorporated herein by reference as indicated.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorize


	EPL Oil & Gas, Inc.

Date: May 7, 2014	By:	/s/ Tiffany J. Thom
		Tiffany J. Thom
		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

INDEX TO EXHIBITS

Exhibit
Number

Exhibit Description

Incorporated by
Reference
Form

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

2.1

Agreement and Plan of Merger between EPL Oil & Gas, Inc., Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., and Clyde Merger Sub, Inc., dated as of March 12, 2014.

8-K

001-16179

2.1

3/13/2014

2.2

Amendment No. 1 to the Agreement and Plan of Merger between EPL Oil & Gas, Inc., Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., and Clyde Merger Sub, Inc., dated as of March 12, 2014.

10-K/A

001-16179

2.7

4/15/2014

3.1

4.1

Third Supplemental Indenture by and among EPL Oil & Gas, Inc., the other Guarantors named therein and U.S. Bank National Association, as Trustee, dated April 18, 2014.

8-K

001-16179

4.1

4/21/2014

10.1

Form of Energy XXI (Bermuda) Limited Voting Agreement, dated March 12, 2014.

8-K

001-16179

10.1

3/13/2014

10.2

Form of EPL Oil & Gas, Inc. Voting Agreement, dated March 12, 2014.

8-K

001-16179

10.2

3/13/2014

31.1

Certification of Principal Executive Officer of EPL Oil & Gas, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Principal Financial Officer of EPL Oil & Gas, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Section 1350 Certification of Principal Executive Officer of EPL Oil & Gas, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Section 1350 Certification of Principal Financial Officer of EPL Oil & Gas, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

* Incorporated herein by reference as indicated.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Three Monthls Ended March 31,

(in thousands)

Weighted average shares