Exhibit 99.1

 

ENERGY XXI GULF COAST, INC.

 

CONSOLIDATED FINANCIAL STATEMENTS

 

JUNE 30, 2015 AND 2014

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2015 AND 2014

 

CONTENTS

 

	Page
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statements of Stockholder’s Equity (Deficit)	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7
Restated Unaudited Quarterly Financial Statements	39

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholder of

Energy XXI Gulf Coast, Inc.

Houston, Texas

 

We have audited the accompanying consolidated balance sheet of Energy XXI Gulf Coast, Inc. and subsidiaries (the “Company”) as of June 30, 2015 and the related consolidated statements of operations, stockholder’s equity (deficit), and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy XXI Gulf Coast, Inc. and subsidiaries at June 30, 2015, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ BDO USA, LLP

Houston, Texas

October 20, 2015

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

 

 

To the Board of Directors and Stockholder

Energy XXI Gulf Coast, Inc.

 

 

We have audited the accompanying consolidated balance sheets of Energy XXI Gulf Coast, Inc. (a Delaware Corporation) and subsidiaries (the “Company”) as of June 30, 2014, and the related consolidated statements of operations, stockholder’s equity (deficit), and cash flows for each of the two fiscal years in the period ended June 30, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy XXI Gulf Coast, Inc. and subsidiaries as of June 30, 2014, and the consolidated results of their operations and their cash flows for each of the two fiscal years in the period ended June 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

 

 

/s/ UHY LLP

 

Houston, Texas

September 3, 2014, except for the effects of the
restatement disclosed in Note 18, as to
which the date is October 20, 2015 

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share information)

 

		June 30,				June 30,
		2015				2014 (Restated)
ASSETS
Current Assets
Cash and cash equivalents		$	718,868			$	9,325
Accounts receivable
Oil and natural gas sales			100,243				167,075
Joint interest billings			12,433				12,898
Other			40,584				4,099
Prepaid expenses and other current assets			20,438				69,367
Deferred income taxes			-				52,011
Restricted cash			6,024				-
Derivative financial instruments			22,229				1,425
Total Current Assets			920,819				316,200
Property and Equipment
Oil and natural gas properties, net - full cost method of accounting, including $436.4 million and $1,165.7 million of unevaluated properties not being amortized at June 30, 2015 and 2014, respectively			3,570,759				6,427,263
Other property and equipment, net			2,074				3,087
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment			3,572,833				6,430,350
Other Assets
Goodwill			-				329,293
Note Receivable from Energy XXI, Inc.			75,861				69,845
Derivative financial instruments			3,898				3,035
Restricted cash			31,000				6,350
Other assets and debt issuance costs, net of accumulated amortization			71,574				42,155
Total Other Assets			182,333				450,678
Total Assets		$	4,675,985			$	7,197,228
LIABILITIES
Current Liabilities
Accounts payable		$	154,492			$	416,576
Accrued liabilities			120,944				85,162
Notes payable			-				21,967
Asset retirement obligations			33,286				79,649
Derivative financial instruments			2,661				31,957
Current maturities of long-term debt			10,647				14,094
Total Current Liabilities			322,030				649,405
Long-term debt, less current maturities			4,238,355				3,396,473
Deferred income taxes			-				657,687
Asset retirement obligations			453,799				480,185
Derivative financial instruments			1,358				4,306
Other liabilities			5,332				2,454
Total Liabilities			5,020,874				5,190,510
Commitments and Contingencies (Note 12)
STOCKHOLDER'S EQUITY (DEFICIT)
Common stock, $0.01 par value, 1,000,000 shares authorized and  100,000 shares issued and outstanding at June 30, 2015 and 2014, respectively			1				1
Additional paid-in capital			2,252,142				2,092,438
Accumulated deficit			(2,597,032	)			(85,721	)
Total Stockholder's Equity (Deficit)			(344,889	)			2,006,718
Total Liabilities and Stockholder's Equity (Deficit)		$	4,675,985			$	7,197,228

 

See accompanying notes to the consolidated financial statements.

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

 

		Year Ended June 30,
		2015				2014 (Restated)				2013 (Restated)
Revenues
Crude oil sales		$	1,051,678			$	1,104,208			$	1,067,687
Natural gas sales			117,282				135,883				112,753
Gain (loss) on derivative financial instruments			235,439				(86,968	)			(21,667	)
Total Revenues			1,404,399				1,153,123				1,158,773
Costs and Expenses
Lease operating			461,935				365,747				337,163
Production taxes			8,385				5,427				5,246
Gathering and transportation			28,864				23,532				24,168
Depreciation, depletion and amortization			691,321				410,462				359,819
Accretion of asset retirement obligations			49,848				30,183				30,885
Impairment of oil and natural gas properties			2,480,425				-				-
Goodwill impairment			329,293				-				-
General and administrative expense			107,217				85,320				63,909
Total Costs and Expenses			4,157,288				920,671				821,190
Operating Income (Loss)			(2,752,889	)			232,452				337,583
Other Income (Expense)
Other income - net			2,143				1,958				1,860
Interest expense - net			(298,336	)			(147,920	)			(108,360	)
Total Other Expense - net			(296,193	)			(145,962	)			(106,500	)
Income (Loss) Before Income Taxes			(3,049,082	)			86,490				231,083
Income Tax Expense (Benefit)			(538,521	)			30,212				29,255
Net Income (Loss)		$	(2,510,561	)		$	56,278			$	201,828

 

See accompanying notes to the consolidated financial statements.

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY (DEFICIT)

(In thousands, except share information)

 

																		Total
														Accumulated				Stockholder's
		Common Stock								Paid-in				Earnings				Equity
		Shares				Value				Capital				(Deficit)				(Deficit)
Balance, June 30, 2012 (Restated)			100,000			$	1			$	1,454,081			$	(118,611	)		$	1,335,471
Returns to parent			-				-				(27,732	)			-				(27,732	)
Common stock dividends			-				-				-				(46,900	)			(46,900	)
Net income			-				-				-				201,828				201,828
Balance, June 30, 2013 (Restated)			100,000				1				1,426,349				36,317				1,462,667
Contributions from parent			-				-				666,089				(3,216	)			662,873
Common stock dividends			-				-				-				(175,100	)			(175,100	)
Net income			-				-				-				56,278				56,278
Balance, June 30, 2014 (Restated)			100,000				1				2,092,438				(85,721	)			2,006,718
Contributions from parent			-				-				287,048				-				287,048
Distribution of assets to parent											(127,344	)			-				(127,344	)
Common stock dividends			-				-				-				(750	)			(750	)
Net loss			-				-				-				(2,510,561	)			(2,510,561	)
Balance, June 30, 2015			100,000			$	1			$	2,252,142			$	(2,597,032	)		$	(344,889	)

 

See accompanying notes to the consolidated financial statements.

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

		Year Ended June 30,
		2015				2014 (Restated)				2013 (Restated)
Cash Flows From Operating Activities
Net income (loss)		$	(2,510,561	)		$	56,278			$	201,828
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			691,321				410,462				359,819
Impairment of oil and natural gas properties			2,480,425				-				-
Goodwill impairment			329,293				-				-
Deferred income tax expense (benefit)			(538,521	)			30,212				29,255
Change in fair value of derivative financial instruments			(52,036	)			69,656				21,010
Accretion of asset retirement obligations			49,848				30,183				30,885
Amortization and write-off of debt issuance costs and other			10,534				6,513				6,898
Interest income accrued to note receivable			(1,910	)			(1,910	)			(1,836	)
Changes in operating assets and liabilities
Accounts receivable			49,491				63,244				1,233
Prepaid expenses and other assets			48,929				4,637				3,377
Settlement of asset retirement obligations			(106,515	)			(57,391	)			(41,939	)
Accounts payable and accrued liabilities			(98,580	)			(72,197	)			62,093
Net Cash Provided by Operating Activities			351,718				539,687				672,623
Cash Flows from Investing Activities
Acquisitions, net of cash acquired			(301	)			(849,641	)			(161,164	)
Capital expenditures			(723,100	)			(785,465	)			(804,918	)
Insurance payments received			3,920				1,983				-
Transfer from (to) restricted cash			(9,675	)			(325	)			-
Proceeds from the sale of properties			16,930				126,265				-
Other, net			-				(3	)			(6	)
Net Cash Used in Investing Activities			(712,226	)			(1,507,186	)			(966,088	)
Cash Flows from Financing Activities
Proceeds from long-term debt			2,586,572				3,084,305				1,571,061
Contributions from (returns to) parent			277,615				170,568				(27,732	)
Dividends to shareholder – common			(750	)			(175,100	)			(46,900	)
Payments on long-term debt			(1,729,034	)			(2,079,072	)			(1,243,545	)
Cash restricted under revolving credit facility related to property sold			(21,000	)			-				-
Debt issuance costs and other			(43,352	)			(23,877	)			(4,813	)
Net Cash Provided by Financing Activities			1,070,051				976,824				248,071
Net Increase (Decrease) in Cash and Cash Equivalents			709,543				9,325				(45,394	)
Cash and Cash Equivalents, beginning of period			9,325				-				45,394
Cash and Cash Equivalents, end of period		$	718,868			$	9,325			$	-

 

See accompanying notes to the consolidated financial statements.

 

 

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1 — Organization and Summary of Significant Accounting Policies

 

Nature of Operations. Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (our “Parent” or “EXXI USA”).  Energy XXI Ltd (“Energy XXI”), indirectly owns 100% of our Parent. References in this report to “us,” “we,” “our,” or “the Company,” are to EGC and its wholly-owned subsidiaries. We are headquartered in Houston, Texas and are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and in the Gulf of Mexico Shelf (“GoM Shelf”).

 

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of EGC and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported consolidated net income, consolidated stockholder’s equity (deficit) or consolidated cash flows. In addition, we have restated previously issued consolidated financial statements to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) as gain (loss) on derivative financial instruments in earnings as a component of revenues and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling test, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement. See Note 18 – Restatement of Previously Issued Consolidated Financial Statements for details of the impact of the restatement.

 

Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.

 

Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

 

Restricted Cash. We maintain restricted escrow funds in trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts are reflected in Restricted cash on our consolidated balance sheets.

 

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2015 and 2014, no allowance for doubtful accounts was necessary.

 

Oil and Natural Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

 

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) ratably over a period of time of not more than four years.

 

 

We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.

 

Depreciation, Depletion and Amortization.  The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves.

 

Weather Based Insurance Linked Securities. We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and natural gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense.

 

Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred.

 

Business Combinations. For properties acquired in a business combination, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes are recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

 

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.

 

Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

 

Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 in connection with the acquisition of EPL Oil & Gas, Inc. and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 – “Goodwill” for more information.

 

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed.

 

 

We previously designated the majority of our derivative instruments as cash flow hedges, however, in connection with preparing our Consolidated Financial Statements for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges related to our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging.  The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Accordingly, our currently outstanding derivative contracts are not accounted for as cash flow hedges. Therefore, changes in fair value of these outstanding derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statement of operations.

 

Additionally, we concluded that certain of our previously issued consolidated financial statements should no longer be relied upon and would need to be restated. Our Consolidated Financial Statements for the year ended June 30, 2015 include (1) a restated balance sheet as of June 30, 2014, (2) restated consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholder’s equity (deficit) for the years ended June 30, 2014 and 2013, and (3) restated unaudited consolidated quarterly financial statements for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013, and March 31, 2015 and 2014. See Note 18 – “Restatement of Previously Issued Consolidated Financial Statements” for more information concerning these restatements.

 

Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the straight-line method, which approximates the interest method.

 

Asset Retirement Obligations. Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

 

Common Stock. Refers to the $0.01 par value per share capital stock as designated in the Company’s Certificate of Incorporation.

 

Revenue Recognition. We recognize oil and natural gas revenue when the product is delivered at the contracted sales price, title is transferred and collectability is reasonable assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at June 30, 2015 and 2014.

 

General and Administrative Expense. Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees directly involved in acquisition, exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2015, 2014 and 2013 was $49.2 million, $64.5 million, and $37.6 million, respectively.

 

Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

 

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements. As a result of changes in our expectations regarding our future taxable income, consistent with net losses recorded during the current year (heavily affected by impairments) we recorded a net increase in our valuation allowance of $445.8 million resulting in a balance of $468.3 million at June 30, 2015. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

 

Note 2 — Recent Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.

 

 

In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

 

In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.

 

Note 3 – Acquisitions and Dispositions

 

Black Elk Interest Acquisition

 

On December 20, 2013, we acquired certain offshore Louisiana interests in West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013, and we are currently the operator of these properties.

 

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):

 

Oil and natural gas properties – evaluated		$	15,821
Oil and natural gas properties – unevaluated			6,586
Asset retirement obligations			(10,503	)
Net working capital *			(1,500	)
Cash paid		$	10,404

 

*Net working capital includes payables.

 

Walter Oil & Gas Corporation Oil and Gas Property Interests Acquisition

 

On March 7, 2014, we acquired certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for total cash consideration of approximately $22.8 million. This acquisition was effective January 1, 2014, and we are currently the operator of these properties.

 

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):

 

Oil and natural gas properties – evaluated		$	23,497
Asset retirement obligations			(705	)
Cash paid		$	22,792

 

We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates. In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; (3) an inflation factor; and (4) a credit adjusted risk-free interest rate. 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 15 – “Fair Value of Financial Instruments”.

 

 

EPL Oil & Gas, Inc. (“EPL”) Acquisition

 

We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method, and EPL is now a wholly owned subsidiary of EGC. Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

 

In connection with the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash ("Cash Election"), or 1.669 shares of Energy XXI common stock ("Stock Election") or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock ("Mixed Election" and together with the Cash Election and the Stock Election, the "Merger Consideration"), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30, 2014 deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 per share in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, 23.3 million shares of Energy XXI common stock were issued and approximately $1,012 million was paid in cash.

 

The following table summarizes the total purchase price of approximately $1,504.3 million (in millions, except per share amounts):

 

Election		EPL Shares				Cash per share				Energy XXI Stock				Cash Paid				Energy XXI Stock Issued				Energy XXI Stock Price on  June 3, 2014				Cash Value of Energy XXI Stock Issued				Total Purchase Price
Cash Election			30.6			$	25.92				0.5595			$	792.6				17.1083			$	21.11			$	361.2			$	1,153.8
Mixed Election*			7.4				25.35				0.5840				186.8				4.3037				21.11				90.8				277.6
Stock Election			1.1				-				1.6690				-				1.9090				21.11				40.3				40.3
Stock Options			0.8				39.00				-				32.6				-								-				32.6
Total			39.9											$	1,012.0				23.3210							$	492.3			$	1,504.3

 

(*) Includes 4.7 million EPL shares that were held by EPL stockholders that did not make an election prior to the May 30, 2014 election deadline.

 

The following table summarizes the final purchase price allocation for EPL as of June 3, 2014, including cash acquired of $206.1 million (in thousands):

 

		EPL Historical				Fair Value Adjustment				Total
						(Unaudited)
Current assets (excluding deferred income taxes)		$	301,592			$	1,274			$	302,866
Oil and natural gas propertiesa
Evaluated (Including net ARO assets)			1,919,699				112,624				2,032,323
Unevaluated			41,896				859,886				901,782
Other property and equipment			7,787				-				7,787
Other assets			16,227				(9,002	)			7,225
Current liabilities (excluding ARO)			(314,649	)			(2,058	)			(316,707	)
ARO (current and long-term)			(260,161	)			(13,211	)			(273,372	)
Debt (current and long-term)			(973,440	)			(52,967	)			(1,026,407	)
Deferred income taxesb			(118,359	)			(340,645	)			(459,004	)
Other long-term liabilities			(2,242	)			797				(1,445	)
Total fair value, excluding  goodwill			618,350				556,698				1,175,048
Goodwillc,d			-				329,293				329,293
Less cash acquired			-				-				(206,075	)
Total purchase price		$	618,350			$	885,991			$	1,298,266

 

 

a.    EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

 

b.    Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit).

 

c.    See Note 4 – “Goodwill” for more information regarding goodwill impairment at December 31, 2014.

 

d.    On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million. Accordingly, the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill.

 

In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates, and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.

 

The fair value estimates of the oil and natural gas properties, and the asset retirement obligations were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value estimate of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.

 

The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, which enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets. During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 – “Goodwill” for more information regarding the impairment of goodwill at December 31, 2014.

 

In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred. For the year ended June 30, 2015, our consolidated statement of operations includes EPL’s operating revenues of $542.8 million and net loss of $1,298.7 million.

 

The following supplemental unaudited pro forma consolidated financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on the historical restated consolidated statements of operations of EGC and EPL for the year ended June 30, 2014 and 2013 (in thousands).

 

 

		Year Ended  June 30,
		2014 (Restated)				2013 (Restated)
		(Unaudited)
Revenues		$	1,783,062				1,877,163
Net income (loss)			(3,827	)			207,518

 

The above supplemental unaudited pro forma consolidated financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments to income from continuing operations for the year ended June 30, 2014 and 2013 were the following:

 

a.

Exclude $45.2 million and $15.7 million, respectively, of EPL’s exploration costs and impairment expense and $1.8 million and $26.9 million, respectively, of gain on sales of assets accounted for under the successful efforts method of accounting to correspond with our full cost method of accounting.

 

b.

Increase DD&A expense by $65.3 million and $120.5 million, respectively for the EPL Properties to correspond with our full cost method of accounting as well as the adjustments to fair value of the acquired assets.

 

c.

Increase interest expense by $50.0 million and $54.0 million, respectively, to reflect interest on the $650 million 6.875% unsecured senior notes due 2024 (the “6.875% Senior Notes”) and on additional borrowings under our revolving credit facility. Decrease interest expense $12.3 million and $13.3 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million 8.25% senior notes due 2018 (the “8.25% Senior Notes”) assumed in the EPL Acquisition.

 

Sale of interests in the Eugene Island 330 and the South Marsh Island 128 fields

 

On April 1, 2014, we sold our interests in the Eugene Island 330 and the South Marsh Island 128 fields to M21K, LLC (“M21K”), which is a wholly owned subsidiary of Energy XXI’s equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million.

 

Distribution of the Grand Isle Gathering System

 

On March 11, 2015, we distributed the Grand Isle gathering system (“Grand Isle Assets”) to our Parent pursuant to an assignment and bill of sale between certain of our subsidiaries and our Parent. The Grand Isle Assets include a liquids gathering system consisting of a system of pipelines, storage tanks, processing facilities, salt water disposal facilities and related facilities and equipment. This distribution resulted in a decrease in additional paid-in-capital with no gain or loss recognized.

 

The following table summarizes the assets and liabilities distributed (in thousands):

 

Oil and natural gas properties		$	201,424
Asset retirement obligations			(6,893	)
Deferred income taxes			(67,187	)
Net assets distributed		$	127,344

 

Sale of interest in the East Bay field

 

On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $68.9 million.

 

 

Note 4 – Goodwill

 

ASC 350, Intangibles—Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed at least annually during the third quarter.

 

Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.

 

At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. In light of the form of the acquisition of EPL (a purchase of stock), this goodwill had no tax basis when recognized, which resulted in no income tax benefit when impaired.

 

In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using an assumed weighted average cost of capital based on market participant data. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.

 

Note 5 – Property and Equipment

 

Property and equipment consists of the following (in thousands):

 

						June 30,
		June 30, 2015				2014 (Restated)
Oil and natural gas properties
Proved properties		$	9,290,982			$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment			(6,156,580	)			(2,985,790	)
Proved properties, net			3,134,402				5,261,562
Unevaluated properties			436,357				1,165,701
Oil and natural gas properties, net			3,570,759				6,427,263
Other property and equipment			3,116				3,173
Less: accumulated depreciation			(1,042	)			(86	)
Other property and equipment, net			2,074				3,087
Total property and equipment,  net of accumulated depreciation, depletion, amortization and impairment		$	3,572,833			$	6,430,350

 

 

The following table summarizes an aging of total costs related to unevaluated properties and wells in progress excluded from the amortization base as of June 30, 2015 (in thousands):

 

		Net Costs Incurred During the Years Ended June 30,																Balance as of
		2012 and prior				2013				2014				2015				June 30, 2015
Unevaluated Properties (acquisition costs)		$	928			$	-			$	435,429			$	-			$	436,357

 

At June 30, 2015, our investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL Acquisition). Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) ratably over a period of time of not more than four years.

 

At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties. Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following: 1) the Lomond North project resulted in a successful production test with commercial production commencing in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the Blackbeard East project expired. Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the year ended June 30, 2015.

 

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the year ended June 30, 2015, our ceiling test computations resulted in impairment of our oil and natural gas properties totaling $2,480.4 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

 

Note 6 – Long-Term Debt

 

Long-term debt consists of the following (in thousands):

 

		June 30,
		2015				2014
Revolving Credit Facility		$	150,000			$	689,000
11.0% Senior Secured Second Lien Notes due 2020			1,450,000				-
8.25% Senior Notes due 2018			510,000				510,000
6.875% Senior Notes due 2024			650,000				650,000
7.5% Senior Notes due 2021			500,000				500,000
7.75% Senior Notes due 2019			250,000				250,000
9.25% Senior Notes due 2017			750,000				750,000
Debt premium, 8.25% Senior Notes due 2018 (1)			29,459				40,567
Original issue discount, 11.0% Notes due 2020			(51,104	)			-
Derivative instruments premium financing			10,647				21,000
Total debt			4,249,002				3,410,567
Less current maturities			10,647				14,094
Total long-term debt		$	4,238,355			$	3,396,473

 

(1)

Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition.

Maturities of long-term debt as of June 30, 2015 are as follows (in thousands):

 

 

Twelve Months Ended June 30,
2016		$	10,647
2017			750,000
2018			660,000
2019			250,000
2020			1,450,000
Thereafter			1,150,000
			4,270,647
Less:  Net original issue discount & debt premium			(21,645	)
Total debt		$	4,249,002

 

Revolving Credit Facility

 

On March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”) in connection with the issuance of $1.45 billion of senior secured second lien notes as described below under “11.0% Senior Secured Second Lien Notes Due 2020.” Under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement became effective:

 

·

reduction of the maximum facility amount to $500 million and establishment of the borrowing base at such $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement;

 

·

addition of provisions to permit EGC to make a loan to EPL in the amount of $325 million using proceeds from the incurrence of additional permitted second lien or third lien indebtedness of EGC and for EPL and its subsidiaries to secure such loan by providing liens on substantially all of their assets that are second in priority to the liens of the lenders under the First Lien Credit Agreement pursuant to the terms of an intercreditor agreement and restricting the transfer of EGC’s rights in respect of such loan or making any prepayment or otherwise making modifications of the terms of such arrangements;

 

·

change in the definition of the stated maturity date of the First Lien Credit Agreement so that it accelerates from April 9, 2018 (the scheduled date of maturity) to a date 210 days prior to the date of maturity of our outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of EPL’s outstanding 8.25% Senior Notes due February 2018 if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018;

 

·

elimination, addition, or modification of certain financial covenants;

 

·

setting the applicable commitment fee under the First Lien Credit Agreement at 0.50% and providing that outstanding amounts drawn under the First Lien Credit Agreement bear interest at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%;

 

·

increase of the threshold requirement for oil and gas properties required to be secured by mortgages to 90% of the value of our (other than EPL and its subsidiaries until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but allowing the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) to remain at 85%;

 

·

addition of certain further restrictions on the prepayment and repayment of our outstanding note indebtedness, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that we have net liquidity at the time thereof of at least $250 million;

 

 

 

·

modification to the restricted payment covenant to substantially limit our ability to make distributions and dividends to parent entities, provided that a distribution of the Grand Isle Assets was permitted (see Note 11 – “Related Party Transactions”);

 

·

qualification on our ability to refinance outstanding indebtedness by requiring that we have pro forma net liquidity of $250 million at the time of such refinancing; and

 

·

modification of the asset disposition covenant to require lender consent for any such disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate; provided, however, that such provision was expressly deemed not to be applicable to certain sales relating to the Grand Isle Assets, as long as we meet certain obligations, such as, among others, maintaining the proceeds from such sales in accounts that are subject to the liens of the lenders.

 

As of June 30, 2015, we had $150.0 million in borrowings and $226.0 million in letters of credit issued under the revolving credit facility. During the year ended June 30, 2015, as a result of the reduction in the borrowing capacity under our Revolving Credit Facility pursuant to the Tenth Amendment, we wrote off $8.9 million of previously capitalized debt issue costs.

 

The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenant on a consolidated basis: a minimum current ratio of no less than 1.0 to 1.0. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. If EPL’s 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the revolving credit facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.

 

Under the First Lien Credit Agreement, as amended under the Tenth Amendment, our rights to make distributions to our shareholder (including ultimately to Energy XXI) are substantially reduced. Generally, under the Tenth Amendment, we are only permitted to make such distributions for income tax liabilities arising for such other entities that relate to the income attributable to us and our subsidiaries, general and administrative expenses not to exceed $2 million in any fiscal year and for payment of insurance premiums in regards to affiliated party insurance agreements.

 

As of June 30, 2015, we were in compliance with all covenants under the First Lien Credit Agreement, other than with respect to the sale of interests in the East Bay field. Since required lender consent to the specific terms of the transaction had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default, which waiver required EPL to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to us.

 

As of July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver to the First Lien Credit Agreement (the “Eleventh Amendment”), which waives certain provisions of the First Lien Credit Agreement to permit us to acquire the equity interest in M21K not already owned by Energy XXI as well as an additional minor acquisition and disposition. Further, the Eleventh Amendment temporarily increased the letter of credit commitment amount within the facility from $300 million to a maximum amount of $305 million through August 31, 2015, after which it reduced back to $300 million. Please see Note 17 – “Subsequent Events.”

 

Based on projected market conditions and commodity prices, we currently expect that we will not be in compliance with certain covenants under the First Lien Credit Agreement in certain future periods. We are focused on reducing our leverage and working with our bank group on certain covenant amendments. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

 

 

11.0% Senior Secured Second Lien Notes Due 2020

 

On March 12, 2015, we issued $1.45 billion in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 (the “11.0% Notes”) pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, Energy XXI, our ultimate parent company, EXXI USA and certain of the EGC’s wholly owned subsidiaries (together with Energy XXI and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the initial purchasers named therein (the “Initial Purchasers”). We received net proceeds of approximately $1.35 billion in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The 11.0% Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.000%. The 11.0% Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. The 11.0% Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15^th and September 15^th, beginning September 15, 2015. We incurred underwriting and direct offering costs of $41.7 million which have been capitalized and are being amortized over the life of the 11.0% Notes. The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the Initial Purchasers’ discount of $53.5 million as well as the direct offering costs.

 

The 11.0% Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The 11.0% Notes are secured by second-priority liens on substantially all of EGC and our subsidiary guarantors’ assets and all of EXXI USA’s equity interests in us, in each case to the extent such assets secure our Revolving Credit Facility. In the future, the 11.0% Notes may be guaranteed by certain of our material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.

 

The 11.0% Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of our future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture. EXXI USA also guarantees the notes on a non-recourse basis limited to the value of equity interests in us that it pledges to secure its guarantee. Although the 11.0% Notes are guaranteed by Energy XXI and EXXI USA, Energy XXI and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.

 

On or after September 15, 2017, we will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, we may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. We will be required to offer to purchase all outstanding 11.0% Notes if a ‘‘triggering event’’ occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a ‘‘triggering event’’ will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. If a change of control, as defined in the 2015 Indenture, occurs, each holder of the 11.0% Notes will have the right to require us to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

 

The 2015 Indenture restricts our ability and the ability of our restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of our assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.

 

 

8.25% Senior Notes Due 2018

 

On June 3, 2014, we assumed the 8.25% Senior Notes in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL's obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes became callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

 

6.875% Senior Notes Due 2024

 

On May 27, 2014, we issued at par $650 million in aggregate principal amount of the 6.875% Senior Notes due March 15, 2024. On June 1, 2015, we completed a registered offer to exchange the 6.875% Senior Notes for a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. EGC incurred underwriting and direct offering costs of approximately $11 million which were capitalized and are being amortized over the life of the 6.875% Senior Notes.

 

On or after March 15, 2019, we will have the right to redeem all or some of the 6.875% Senior Notes at redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, we may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. We are required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.

 

The indenture governing the 6.875% Senior Notes, among other things, limits our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

7.5% Senior Notes Due 2021

 

On September 26, 2013, we issued at par $500 million aggregate principal amount of 7.5% unsecured senior notes due December 15, 2021 (the “7.5% Senior Notes”). In April 2014, we completed a registered offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. We incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.

 

On or after December 15, 2016, we will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, we may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, we may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. We are required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.

 

The indenture governing the 7.5% Senior Notes limits, among other things, our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

7.75% Senior Notes

 

On February 25, 2011, we issued at par $250 million aggregate principal amount of 7.75% unsecured senior notes due June 15, 2019 (the “7.75% Old Senior Notes”). On July 7, 2011, EGC exchanged the 7.75% Old Senior Notes for newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) with identical terms and conditions as the 7.75% Old Senior Notes.

 

 

The 7.75% Senior Notes became callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. We incurred underwriting and direct offering costs of $3.1 million were capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.

 

9.25% Senior Notes Due 2017

 

On December 17, 2010, we issued at par $750 million aggregate principal amount of 9.25% unsecured senior notes due December 15, 2017 (the “9.25% Old Senior Notes”). On July 8, 2011, EGC exchanged $749 million of the 9.25% Old Senior Notes for $749 million of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act with identical terms and conditions. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

 

The 9.25% Senior Notes became callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. We incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.

 

Guarantee of Securities Issued by EGC

 

We are the issuer of each of the 11.0% Notes, the 6.875% Senior Notes, 7.5% Senior Notes, 9.25% Senior Notes and 7.75% Senior Notes, which are fully and unconditionally guaranteed by us and each of our existing and future material domestic subsidiaries other than EPL and its subsidiaries. Energy XXI and its subsidiaries, other than us, do not have significant independent assets or operations. We are permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility.”

 

Derivative Instruments Premium Financing

 

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of June 30, 2015 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $10.6 million and $21.0 million, respectively.

 

Interest Expense

 

Interest expense consisted of the following (in thousands):

 

		Year Ended June 30,
		2015				2014				2013
Revolving Credit Facility		$	25,506			$	13,956			$	11,816
11.0% Senior Secured Second Lien Notes due 2020			48,505				-				-
8.25% Senior Notes due 2018			42,075				3,507				-
6.875% Senior Notes due 2024			44,701				4,096				-
7.50% Senior Notes due 2021			37,500				28,542				-
7.75% Senior Notes due 2019			19,375				19,375				19,375
9.25% Senior Notes due 2017			69,375				69,375				69,375
Amortization of debt issue cost - Revolving Credit Facility			12,491				3,076				4,303
Accretion of original debt issue discount, 11.0% Notes due 2020			2,358				-				-
Amortization of debt issue cost – 11.0% Notes due 2020			1,887				-				-
Amortization of fair value premium – 8.25% Senior Notes due 2018			(11,108	)			(841	)			-
Amortization of debt issue cost – 6.875% Senior Notes due 2024			1,127				102				-
Amortization of debt issue cost – 7.50% Senior Notes due 2021			1,051				783				-
Amortization of debt issue cost – 7.75% Senior Notes due 2019			388				388				388
Amortization of debt issue cost – 9.25% Senior Notes due 2017			2,358				2,206				2,206
Derivative instruments financing and other			747				874				897
Bridge commitment fee			-				2,481				-
		$	298,336			$	147,920			$	108,360

 

 

 

Note 7 – Notes Payable

 

On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million with an annual interest rate of 1.923%. The notes matured and were repaid on May 1, 2015.

 

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million with an annual interest rate of 1.723%. The note matured and was repaid on May 3, 2015. 

 

In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million with an annual interest rate of 1.623%. The note matured and was repaid on April 26, 2014.

 

Note 8 – Asset Retirement Obligations

 

The following table describes the changes in our asset retirement obligations (in thousands):

 

		Year Ended June 30,
		2015				2014
Beginning of period total		$	559,834			$	287,818
Liabilities acquired			-				284,661
Liabilities incurred and true-up to liabilities settled			40,820				41,216
Liabilities settled			(106,573	)			(57,391	)
Liabilities sold			(58,626	)			-
Transferred to Parent			(6,893	)			-
Revisions in estimated cash flows			8,675				(26,653	)
Accretion expense			49,848				30,183
End of period total			487,085				559,834
Less:  End of period, current portion			33,286				79,649
End of period, noncurrent portion		$	453,799			$	480,185

 

Note 9 – Derivative Financial Instruments

 

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We previously designated the majority of our derivative instruments as cash flow hedges, however, in connection with preparing our Consolidated Financial Statements for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges related to our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging.  The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Accordingly, our currently outstanding derivative contracts are not accounted for as cash flow hedges. Therefore, changes in fair value of these outstanding derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statement of operations.

 

 

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

 

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.

 

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

 

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts, keeping one natural gas contract.

 

As of June 30, 2015, we had the following net open crude oil derivative positions:

 

										Weighted Average Contract Price
		Type of				Volumes				Collars/Put
Remaining Contract Term		Contract		Index			(MBbls)				Sub Floor				Floor				Ceiling
July 2015 - December 2015		Three-Way Collars		ARGUS-LLS			3,680			$	32.50			$	45.00			$	75.00
July 2015 - December 2015		Collars		ARGUS-LLS			920								80.00				123.38
July 2015 - December 2015		Collars		NYMEX-WTI			276								75.00				85.00
July 2015 - December 2015		Bought Put		NYMEX-WTI			552								90.00
July 2015 - December 2015		Sold Put		NYMEX-WTI			(552	)							90.00
January 2016 - June 2016		Collars		NYMEX-WTI			2,548								51.43				74.70
July 2016 - December 2016		Collars		NYMEX-WTI			2,576								51.43				74.70

 

As of June 30, 2015, we had the following net open natural gas derivative position:

 

Type of

Volumes

Swaps

Remaining Contract Term

Contract

Index

(MMBtu)

Fixed Price

July 2015 - December 2015

Swaps

NYMEX-HH

791

$

4.31

 

The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):

 

		Asset Derivative Instruments												Liability Derivative Instruments
		June 30, 2015						June 30, 2014						June 30, 2015						June 30, 2014
		Balance  Sheet Location		Fair Value				Balance  Sheet Location		Fair Value				Balance  Sheet Location		Fair Value				Balance  Sheet Location		Fair Value
Derivative financial instruments		Current		$	51,024			Current		$	17,380			Current		$	31,456			Current		$	47,912
		Non- Current			11,980			Non-Current			9,595			Non-Current			9,440			Non-Current			10,866
Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement					63,004						26,975						40,896						58,778
Derivative financial instruments		Current			(28,795	)		Current			(15,955	)		Current			(28,795	)		Current			(15,955	)
		Non-Current			(8,082	)		Non-Current			(6,560	)		Non-Current			(8,082	)		Non-Current			(6,560	)
Gross amounts offset in Balance Sheets					(36,877	)					(22,515	)					(36,877	)					(22,515	)
Net amounts presented in Balance Sheets		Current			22,229			Current			1,425			Current			2,661			Current			31,957
		Non-Current			3,898			Non-Current			3,035			Non-Current			1,358			Non-Current			4,306
				$	26,127					$	4,460					$	4,019					$	36,263

 

 

The following table presents information about the components of the gain (loss) on derivative instruments (in thousands):

 

		Year Ended June 30,
Gain (loss) on derivative financial instruments		2015				2014 (Restated)				2013 (Restated)
Cash Settlements, net of purchased put premium amortization		$	81,049			$	(17,312	)		$	(1,417	)
Proceeds from monetizations			102,354				-				760
Change in fair value			52,036				(69,656	)			(21,010	)
Total (gain) loss on derivative financial instruments		$	235,439			$	(86,968	)		$	(21,667	)

 

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At June 30, 2015, we had no deposits for collateral with our counterparties.

 

Note 10 – Supplemental Cash Flow Information

 

The following table presents our supplemental cash flow information (in thousands):

 

		Year Ended June 30,
		2015				2014				2013
Cash paid for interest		$	230,978			$	132,761			$	99,377

 

The following table presents our non-cash investing and financing activities (in thousands):

 

		Year Ended June 30,
		2015				2014				2013
Financing of insurance premiums		$	-			$	21,967			$	22,524
Derivative instruments premium financing			12,025				11,257				18,231
Changes in capital expenditures accrued in accounts payable			(168,569	)			115,696				37,274
Non-cash change related to property disposition			(64,295	)			-				-
Non-cash distribution of assets to Parent			(127,344	)			-				-
Non-cash changes in assets retirement obligations			49,495				299,225				(9,820	)
Stock contributions from parent for EPL Acquisition			-				492,305				-
Non-cash debt issuance costs contributed by Energy XXI			5,329				-				-
Changes in note receivable from Energy XXI, Inc.			4,104				-				-

 

 

Note 11 — Related Party Transactions

 

On March 11, 2015, we distributed the Grand Isle Assets to our Parent pursuant to an assignment and bill of sale between certain of our subsidiaries and our Parent. The Grand Isle Assets include a liquids gathering system consisting of a system of pipelines, storage tanks, processing facilities, salt water disposal facilities and related facilities and equipment. This distribution resulted in a decrease in additional paid-in-capital of $127.3 million, reflecting the net book value of the assets distributed, net of asset retirement obligations and related deferred tax liabilities.

 

Also on March 11, 2015, we entered into an agreement with our Parent providing for the transportation of certain of our oil production on the Grand Isle gathering system. For the year ended June 30, 2015, we incurred charges totaling $7.7 million related to transportation services under this agreement.

 

During the year ended June 30, 2015, 2014 and 2013, we paid dividends of $0.8 million, $175.1 million and $46.9 million, respectively, to our Parent. During the year ended June 30, 2015, 2014 and 2015, we received (returned) approximately $287.0 million, $662.9 million and $(27.7) million, respectively, from (to) our Parent.

 

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc. our indirect parent, bearing simple interest of 2.78% per annum. The note matures on December 16, 2021. Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium. Interest and principal are payable at maturity. Interest on the note receivable amounted to approximately $1.9 million, $1.9 million and $1.8 million for the years ended June 30, 2015, 2014 and 2013. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of June 30, 2015.

 

During the year ended June 30, 2015, we reimbursed $6.3 million to our affiliate Energy XXI Insurance Limited for windstorm insurance coverage.  The periods covered are from June 1, 2014 through June 1, 2015 and from June 1, 2015 through June 1, 2016.

 

We have no employees; instead we receive management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services for the years ended June 30, 2015, 2014 and 2013 was approximately $91.4 million, $81.4 million and $62.5 million, respectively. These costs are included in general and administrative expense.

 

Prior to M21K acquiring the interests in certain oil and natural gas fields owned by LLOG Exploration Offshore, L.L.C. ( the “LLOG Exploration acquisition”) in August 2013, we received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties were purchased by M21K on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the years ended June 30, 2015, 2014 and 2013, we received management fees of $3.3 million, $3.8 million and $1.7 million, respectively.

 

On April 1, 2014, we sold our interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K and on June 3, 2014, we transferred 100% of our interests in the South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions.

 

In order to enhance our ability to pursue alternative financing structures, Energy XXI’s Board of Directors (the “Energy XXI Board”) appointed one of its members, James LaChance, to serve as interim Chief Strategic Officer. In that position, Mr. LaChance pursued discussions with our lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed by Energy XXI’s Chief Executive Officer, in consultation with the Energy XXI Board. In light of the significant increase in the amount of time Mr. LaChance was required to spend performing in this new role, on February 23, 2015, Energy XXI and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance was paid $200,000 per month for his services as interim Chief Strategic Officer. For the year ended June 30, 2015, Mr. LaChance received consulting fees of $1.1 million under the Consulting Agreement.

 

In accordance with the Consulting Agreement and based on certain objective criteria as set forth therein, Mr. LaChance received a success fee in connection with the issuance of the 11.0% Notes. In accordance with the terms of the Consulting Agreement, fifty percent of the success fee was required to be paid to Mr. LaChance in the form of cash-settled restricted stock units (“RSUs”), and Mr. LaChance elected to receive the remaining 50% of the success fee in the form of RSUs issued by Energy XXI on the same terms, subject to certain limitations. On March 12, 2015, based on Energy XXI’s stock price of $3.04 per share, which was the value weighted average price of Energy XXI’s common stock for the period from December 1, 2014 through January 31, 2015 as defined by the Consulting Agreement, Mr. LaChance was awarded 1,644,737 RSUs by Energy XXI. Based on Energy XXI’s closing stock price of $3.24 on March 12, 2015, the fair value of these RSUs was $5.3 million, which amount reflects the number of RSUs awarded by Energy XXI. EGC recorded this non-cash contribution by EXXI for the success fee as debt issuance costs.

 

Mr. LaChance’s duties as interim Chief Strategic Officer were separate from, and in addition to, his responsibilities as a member of the Energy XXI Board. The Consulting Agreement expired on July 15, 2015. On October 9, 2015, the Energy XXI Board determined that the positions of Chief Executive Officer and Chairman of the Board should be held by two different individuals. As a result of that determination, the Energy XXI Board elected Mr. LaChance to serve as Energy XXI’s Chairman of the Board, effective as of October 15, 2015, to serve in such capacity until his earlier resignation or removal. Mr. LaChance will not receive any compensation for serving as Chairman of the Energy XXI Board, other than pursuant to director compensation programs that are applicable to Energy XXI’s other non-employee directors.

 

Energy XXI’s Board has recently learned that Energy XXI’s Chief Executive Officer borrowed funds from personal acquaintances or their affiliates, certain of whom provided services to the Company totaling $34.7 million, $38.7 million and $38.9 million during the years ended June 30, 2015, 2014 and 2013, respectively.  The Energy XXI Board also learned that Norman Louie, one of Energy XXI’s directors, made a personal loan to the Energy XXI Chief Executive Officer in 2014 at a time prior to when Mr. Louie became a director of Energy XXI.  At the time the loan was made, Mr. Louie was a managing director at Mount Kellett Capital Management LP, which at the time, and as of June 30, 2015, owned a majority interest in Energy XXI M21K, an equity investee of Energy XXI, and 6.3% of Energy XXI’s outstanding common stock.

 

 

Note 12 — Commitments and Contingencies

 

Lease Commitments. We have operating leases for office space and equipment, which expire on various dates through December 2022. Expense relating to operating obligations for the year ended June 30, 2015, 2014 and 2013 was $31.0 million, $23.4 million, and $20.1 million, respectively. Future minimum commitments as of June 30, 2015 under these operating obligations are as follows (in thousands):

 

2016		$	1,231
2017			1,010
2018			542
2019			542
2020			135
Thereafter			-
Future minimum commitments		$	3,460

 

Litigation.   We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.

 

Letters of Credit and Performance Bonds.   As of June 30, 2015, we had $226 million in letters of credit and $319.2 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), approximately $157.5 million of our performance bonds are lease and/or area bonds issued to the BOEM that assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $161.7 million in performance bonds issued to predecessor third party assignors, including certain state regulatory bodies of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for exemption via waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.

 

On September 22, 2015, the BOEM issued Draft Guidance relating to supplemental bonding procedures that will, among other things, eliminate the “waiver” exemption currently allowed by BOEM with respect to supplemental bonding and, instead, broaden the self-insurance approach that would allow more operators on the OCS to seek self-insurance for a portion of their supplemental bond obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. In addition, the Draft Guidance would implement a phased-in period for establishing compliance with supplemental bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored plan” that is approved by the BOEM and requires payment of the supplemental bonding amount in three equal installment of one-third each, by no later than 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the tailored plan. Furthermore, with issuance of an Advanced Notice of Proposed Rulemaking in August 2014, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters.

 

In connection with the acquisition of the equity interests of M21K in August 2015 as described in Note 17 – “Subsequent Events,” we increased our performance bonds issued to the BOEM by $60.4 million.

 

Drilling Rig Commitments. The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of June 30, 2015, we had the following three drilling rig commitments:

 

1)  $47,000 per day through September 7, 2015 plus minimum commitment fee of $3.6 million,

2)  $37,000 per day through August 11, 2015, and

3)  $70,000 per day through August 14, 2015.

 

At June 30, 2015, future minimum commitments under these contracts totaled $11.5 million.

 

  

Other. We maintain restricted escrow funds as required by certain contractual arrangements. At June 30, 2015, our restricted cash included $10 million in cash collateral associated with our bonding requirements, $21 million related to the East Bay sale which will remain restricted until our next borrowing base redetermination and approximately $6 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field which will be transferred to the buyer of our interests in that field.

 

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 to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material.

 

Note 13 – Income Taxes

 

We are a U.S. Delaware company and a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group. We operate through our various subsidiaries in the U.S.; accordingly, income taxes have been provided based upon the tax laws and rates of the U.S. as they apply to our current ownership structure. ASC Topic 740 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated financial reporting group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the year-to-date reporting period. We have recorded no income tax related intercompany balances with affiliates. However, during the second quarter of fiscal year 2015, we recorded a goodwill impairment charge of $329 million (see Note 4 - Goodwill). In light of the form of the transaction related to the acquisition of EPL on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition during fiscal year 2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes.

 

The restatement (discussed in Note 18) did not require us to amend any previous income tax filings as the changes in the financial accounting method for derivatives and the resulting effect on depletion, depreciation, and amortization had no effect on taxable income (or loss) as determined for any year. Deferred tax balances related to the changes in balance sheet carrying amounts for derivative instruments and oil and gas properties were revised as required by the adjustments to pre-tax book income.

 

In the current year, changes in our expectations regarding our future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments), caused us to record a net increase in our valuation allowance of $445.8 million resulting in a balance of $468.3 million at June 30, 2015. We recorded this valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

 

The components of our income tax expense (benefit) are as follows (in thousands):

 

		Year Ended June 30,
		2015				2014 (Restated)				2013 (Restated)
Current		$	-			$	-			$	(2,461	)
Deferred			(538,521	)			30,212				31,716
Total income tax expense (benefit)		$	(538,521	)		$	30,212			$	29,255

 

 

The following is a reconciliation of statutory income tax expense to our income tax expense (benefit) (in thousands):

 

		Year Ended June 30,
		2015				2014 (Restated)				2013 (Restated)
Income (loss) before income taxes		$	(3,049,082	)		$	86,490			$	231,083
Statutory rate			35	%			35	%			35	%
Income tax expense (benefit) computed at statutory rate			(1,067,179	)			30,272				80,879
Reconciling items
Change in valuation allowance			445,756				-				(101,522	)
Tax return to provision adjustment to oil and natural gas properties			83				-				52,071
State income taxes (benefit), net of federal tax benefit			(32,479	)			-				(2,461	)
Goodwill impairment			115,253				-				-
Transaction costs			28				-				-
Other – Net			17				(60	)			288
Income tax expense (benefit)		$	(538,521	)		$	30,212			$	29,255

 

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):

 

		June 30,
		2015				2014 (Restated)
Deferred tax assets – current
Asset retirement obligation		$	12,411			$	44,182
Other			-				7,829
Total deferred tax assets - current			12,411				52,011
Deferred tax liabilities - current
Other			(64	)			-
Total deferred tax liabilities - current			(64	)			-
Valuation allowance			(12,347	)			-
Deferred tax assets – non current
Asset retirement obligation			162,876				61,154
Tax loss carryforwards on U.S. operations			331,872				387,331
Deferred state taxes			54,973				22,494
Non-current debt			19,651				-
Other			7,835				24,901
Total deferred tax assets – non current			577,207				495,880
Deferred tax liabilities
Oil, natural gas properties and other property and equipment			(54,768	)			(1,066,700	)
Cancellation of debt			(8,885	)			(8,842	)
Tax partnership activity			(57,642	)			(55,531	)
Total deferred tax liabilities – non current			(121,295	)			(1,131,073	)
Valuation allowance			(455,912	)			(22,494	)
Net deferred tax liability		$	-			$	(605,676	)
Reflected in the accompanying balance sheet as
Current deferred tax asset (liability)		$	-			$	52,011
Non-current deferred tax liability		$	-			$	(657,687	)

 

 

At June 30, 2015, the U.S. consolidated tax group had a federal tax loss carryforward (“NOLs”) of approximately $948 million and a state income tax loss carryforwards of approximately $771 million including amounts carried into the Company’s U.S. group from the EPL acquisition. The regular U.S. federal income tax NOL will expire in various amounts beginning in 2024 and ending in 2036. As of June 30, 2015, Energy XXI Gulf Coast, Inc. was the primary contributor of the federal and state loss carryforwards to the U.S. consolidated tax group.

 

Section 382 of the Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change” and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation (including stock of the U.S. Parent) by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of the Company’s stock at the time of the ownership change by the applicable long-term tax exempt rate (ranging between approximately 2.5% and 3.27%). Any unused annual limitation may be carried over to subsequent years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008, and a second ownership change on November 3, 2010. EPL similarly experienced an ownership change in 2009 and upon its acquisition in 2014. Based upon the Company’s determination of its annual limitation related to this ownership change, management believes that Section 382 should not otherwise limit the Company’s ability to utilize its federal or state NOLs or other attribute carryforwards during their applicable carryforward periods. However, if such an ownership change were to occur in future periods with current commodity pricing, substantial limitations on the use of carryovers under Section 382 is likely. Management will continue to monitor the potential impact of Code Sections 382 and 383 in future periods with respect to NOL and other tax attribute carryforwards and will reassess realization of these carryforwards periodically.

 

The U.S. Parent filed our initial tax return for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2014. Tax years ended June 30, 2012 through 2015 remain open to examination under the applicable statute of limitations in the U.S. and state tax jurisdictions in which the Company and its affiliates file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. On January 12, 2015, the IRS formally notified the U.S. Parent that they had completed their examination of our U.S. federal income tax return for the year ended June 30, 2013, and that no changes were proposed to the tax reported (zero) or any tax attribute carried forward.

 

We have a remaining valuation allowance of $55 million related to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more likely-than-not basis, are realizable due to our current focus on offshore operations. However, an intercompany transaction generated current year Louisiana-only taxable income this period; thus we have released $1.8 million of previously recorded Louisiana valuation allowance as a discrete item this quarter. While the U.S. consolidated group historically has paid no (significant) cash taxes, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We are a party to an intercompany agreement whereby we would be responsible for funding consolidated U.S. federal income tax payments. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

 

Note 14— Concentrations of Credit Risk

 

Major Customers. We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated natural gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

 

 

Shell Trading Company (“Shell”) accounted for approximately 29%, 45%, and 35% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014, and 2013, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26%, 43%, and 37% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014, and 2013, respectively. Chevron USA (“Chevron”) accounted for approximately 24% of our total oil and natural gas revenues during the year ended June 30, 2015. J.P. Morgan Ventures Energy Corporation accounted for 12% of our total oil and natural gas revenues during the year ended June 30, 2013. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell, ExxonMobil or Chevron curtailed their purchases.

 

Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

 

Derivative Instruments. Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We believe that our credit risk related to the futures and swap contracts is no greater than the risk associated with the contracts they hedge and that the mitigation of price risk through our hedging activities reduces volatility in our financial position and cash flows from period to period and lowers our overall business risk.

 

Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation.

 

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

 

Note 15 — Fair Value of Financial Instruments

 

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

 

·

Level 1 – quoted prices in active markets for identical assets or liabilities.

·

Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

·

Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

 

For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the 11.0% Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, and 6.875% Senior Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

 

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 – “Derivative Financial Instruments.”

 

 

During the year ended June 30, 2015, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 2 financial instruments (in thousands):

 

		Level 2
		As of June 30,				As of June 30,
			2015				2014
Assets:
Oil and natural gas derivatives		$	63,004			$	26,975
Liabilities:
Oil and natural gas derivatives		$	40,896			$	58,778

 

The following table sets forth the carrying values and estimated fair values of our long-term indebtedness which are classified as Level 2 financial instruments (in thousands):

 

 

		June 30, 2015								June 30, 2014
			Carrying Value				Estimated Fair Value				Carrying Value				Estimated Fair Value
Revolving credit facility		$	150,000			$	150,000			$	689,000			$	689,000
11% Senior Secured Second Lien Notes due 2020			1,398,896				1,276,000				-				-
8.25% Senior Notes due 2018			539,459				306,000				550,567				545,700
6.875% Senior Notes due 2024			650,000				211,250				650,000				663,000
7.5% Senior Notes due 2021			500,000				164,925				500,000				541,250
7.75% Senior Notes due 2019			250,000				92,135				250,000				269,480
9.25% Senior Notes due 2017			750,000				413,160				750,000				806,630
		$	4,238,355			$	2,613,470			$	3,389,567			$	3,515,060

 

The 11.0% Notes, the 8.25% Senior Notes, the 6.875% Senior Notes, and the 7.5% Senior Notes  each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings.  Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at June 30, 2015 are not material.

 

 

Note 16 — Prepayments and Accrued Liabilities

 

Prepayments and accrued liabilities consist of the following (in thousands):

 

 

		June 30,
		2015				2014
Prepaid expenses and other current assets
Advances to joint interest partners		$	1,294			$	10,336
Insurance			2,869				36,451
Inventory			7,867				7,020
Royalty deposit			3,137				12,262
Other			5,271				3,298
Total prepaid expenses and other current assets		$	20,438			$	69,367
Accrued liabilities
Advances from joint interest partners			3,060				2,667
Interest payable			82,885				26,490
Accrued hedge payable			1,399				7,874
Undistributed oil and gas proceeds			19,776				34,473
Severance taxes payable			843				8,014
Other			12,981				5,644
Total accrued liabilities		$	120,944			$	85,162

 

Note 17 — Subsequent Events

 

During July through September 2015, we repurchased approximately $253.7 million, $50.4 million and $123.7 million in aggregate principal amount of the 7.5% Senior Notes, the 6.875% Senior Notes and the 7.75% Senior Notes, respectively, in open market transactions at a total price of approximately $94.4 million. In the quarter ended September 30, 2015, we will record a gain on the repurchase of approximately $333.4 million less the amount of associated debt issue costs and the notes will be cancelled.

 

On August 11, 2015, pursuant to the M21K Purchase Agreement, we acquired the equity interests of M21K for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing. The sellers retained certain overriding royalty interests applicable only to the extent that production proceeds during any calendar month average in excess of $65.00/Bbl WTI and $3.50/MMbtu Henry Hub and limited to a term of four years or an aggregate amount of $20 million, whichever occurs earlier. In addition, with respect to the Eugene Island 330 and South Marsh Island 128 fields, in the event we sell our interest in one or both of these fields, the overriding royalty interests with respect to such sold field shall terminate; provided, however if such sale occurs within four years of the effective date of the M21K Purchase Agreement and the consideration received for such sale is greater than the allocated value for such field as specified in the M21K Purchase Agreement, then we are obligated to pay an amount equal to 20% of the portion of the consideration received in excess of the specified allocated value of such field. Prior to this transaction which is effective as of August 1, 2015, Energy XXI had owned a 20% interest in M21K through its investment in EXXI M21K.

 

On August 13, 2015, we sold our interest in a pipeline originating at East Cameron Block 338 and terminating at Vermillion Block 265 for $4.2 million in cash plus assumption of abandonment costs and certain repairs.

 

Note 18 – Restatement of Previously Issued Consolidated Financial Statements

 

In connection with preparing our Consolidated Financial Statements for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging.  The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment.  Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings.  Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.

 

 

The effects of the restatement on our consolidated financial statements are summarized below:

 

·

Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue;

·

Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue;

·

Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and

·

Resulting adjustments required to deferred income taxes and income tax expense (benefit).

 

While these non-cash reclassifications impact revenues, net income (loss) in each period and total stockholder’s equity, they have no material impact on cash flows. See additional disclosures of the effects of the restatement within Notes 3, 5, 9, and 13. Details of the impact of the restatement on stockholder’s equity as of June 30, 2012, on the balance sheet as of June 30, 2014 and on the statements of operations for the years ended June 30, 2014 and 2013 are as follows:

 

		As of June 30, 2012
		As Reported				Adjustment				Restated
		(In thousands)
Common Stock		$	1			$	-			$	1
Paid-In Capital			1,454,081				-				1,454,081
Accumulated deficit			(57,172	)			(61,439	)			(118,611	)
Accumulated Other Comprehensive Income			57,603				(57,603	)			-
Total Stockholder's Equity		$	1,454,513			$	(119,042	)		$	1,335,471

 

The adjustment to accumulated deficit is comprised of the following cumulative effects (in thousands):

 

Change in accounting for derivative financial instruments		$	88,656
Related impact on ceiling test impairment			(187,800	)
Related impact on depreciation, depletion and amortization			68,736
Total pre-tax adjustments			(30,408	)
Related income tax provision			31,031
Net after-tax adjustments		$	(61,439	)

 

 

		As of June 30, 2014
		As Reported				Adjustment				Restated
		(In thousands)
Total Current Assets		$	316,200			$	-			$	316,200
Property and Equipment
Oil and natural gas properties, net			6,524,602				(97,339	)			6,427,263
Other property and equipment			3,087				-				3,087
Total Property and Equipment, net			6,527,689				(97,339	)			6,430,350
Total Other Assets			450,678				-				450,678
Total Assets		$	7,294,567			$	(97,339	)		$	7,197,228
Total Current Liabilities		$	649,405			$	-			$	649,405
Deferred Income Taxes			691,779				(34,092	)			657,687
Other Non-Current Liabilities			3,883,418				-				3,883,418
Total Liabilities			5,224,602				(34,092	)			5,190,510
Stockholder's Equity
Common stock			1				-				1
Additional paid-in capital			2,092,438				-				2,092,438
Accumulated deficit			(2,040	)			(83,681	)			(85,721	)
Accumulated other comprehensive loss, net of income taxes			(20,434	)			20,434				-
Total Stockholder's Equity			2,069,965				(63,247	)			2,006,718
Total Liabilities and Stockholder's Equity		$	7,294,567			$	(97,339	)		$	7,197,228

 

 

		Year Ended June 30, 2014
		As Reported				Adjustment				Restated
		(In thousands)
Revenues
Crude oil sales		$	1,091,223			$	12,985			$	1,104,208
Natural gas sales			139,502				(3,619	)			135,883
Loss on derivative financial instruments			-				(86,968	)			(86,968	)
Total Revenues			1,230,725				(77,602	)			1,153,123
Costs and Expenses
Depreciation, depletion and amortization			419,754				(9,292	)			410,462
Loss on derivative financial instruments			5,704				(5,704	)			-
All other costs and expenses			510,209				-				510,209
Total Costs and Expenses			935,667				(14,996	)			920,671
Operating Income			295,058				(62,606	)			232,452
Other Income (Expense)
Other income, net			1,958				-				1,958
Interest expense			(147,920	)			-				(147,920	)
Total Other Expense, net			(145,962	)			-				(145,962	)
Income Before Income Taxes			149,096				(62,606	)			86,490
Income Tax Expense			52,124				(21,912	)			30,212
Net Income		$	96,972			$	(40,694	)		$	56,278
Net Income		$	96,972			$	(40,694	)		$	56,278
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			(61,683	)			61,683				-
Effective portion reclassified to earnings during the period			(10,215	)			10,215				-
Total Other Comprehensive Loss			(71,898	)			71,898				-
Income Tax Benefit			(25,164	)			25,164				-
Net Other Comprehensive Loss			(46,734	)			46,734				-
Comprehensive Income		$	50,238			$	6,040			$	56,278

 

 

		Year Ended June 30, 2013
		As Reported				Adjustment				Restated
		(In thousands)
Revenues
Crude oil sales		$	1,080,982			$	(13,295	)		$	1,067,687
Natural gas sales			127,863				(15,110	)			112,753
Loss on derivative financial instruments			-				(21,667	)			(21,667	)
Total Revenues			1,208,845				(50,072	)			1,158,773
Costs and Expenses
Depreciation, depletion and amortization			372,252				(12,433	)			359,819
Loss on derivative financial instruments			1,915				(1,915	)			-
All other costs and expenses			461,371				-				461,371
Total Costs and Expenses			835,538				(14,348	)			821,190
Operating Income			373,307				(35,724	)			337,583
Other Income (Expense)
Other income, net			1,860				-				1,860
Interest expense			(108,360	)			-				(108,360	)
Total Other Expense, net			(106,500	)			-				(106,500	)
Income Before Income Taxes			266,807				(35,724	)			231,083
Income Tax Expense			83,431				(54,176	)			29,255
Net Income		$	183,376			$	18,452			$	201,828
Net Income		$	183,376			$	18,452			$	201,828
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			(8,348	)			8,348				-
Effective portion reclassified to earnings during the period			(39,810	)			39,810				-
Total Other Comprehensive Loss			(48,158	)			48,158				-
Income Tax Benefit			(16,855	)			16,855				-
Net Other Comprehensive Loss			(31,303	)			31,303				-
Comprehensive Income		$	152,073			$	49,755			$	201,828

 

Note 19 – Supplementary Oil and Gas Information – Unaudited

 

The supplementary data presented reflects information for all of our oil and gas producing activities. Costs incurred for oil and gas property acquisition, exploration and development activities are as follows (in thousands):

 

		Year Ended June 30,
		2015				2014				2013
Property acquisitions
Proved		$	-			$	2,046,879			$	108,825
Unevaluated			2,304				924,882				52,339
Exploration costs			38,183				153,136				168,512
Development costs			608,605				632,262				633,868

 

Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to proved properties as the properties are evaluated or over the life of the reservoir. Wells in progress are transferred into the amortization base once the results of drilling activities are known. We had no exploratory wells in progress at June 30, 2015. At June 30, 2015, we excluded from the amortization base the following costs related to unevaluated property costs (in thousands):

 

 

		Net Costs Incurred During the Years Ended June 30,																Balance as of
		2012 and prior				2013				2014				2015				June 30, 2015
Unevaluated Properties (acquisition costs)		$	928			$	-			$	435,429			$	-			$	436,357

 

Estimated Net Quantities of Oil and Natural Gas Reserves

 

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by our reservoir engineers and audited by NSAI. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

 

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows:

 

		Oil				Natural Gas				Total
		(MBbls)				(MMcf)				(MBOE)
Proved reserves at June 30, 2012			84,793				208,990				119,624
Production			(10,318	)			(32,354	)			(15,710	)
Extensions and discoveries			40,690				40,714				47,476
Revisions of previous estimates			14,380				7,903				15,697
Reclassification of proved undeveloped			(1,123	)			(1,755	)			(1,416	)
Purchases of reserves			5,225				45,623				12,829
Proved reserves at June 30, 2013			133,647				269,121				178,500
Production			(10,978	)			(32,754	)			(16,437	)
Extensions and discoveries			17,141				19,703				20,424
Revisions of previous estimates			(3,567	)			(29,822	)			(8,537	)
Sales of reserves			(4,159	)			(3,378	)			(4,722	)
Purchases of reserves			53,305				141,986				76,970
Proved reserves at June 30, 2014			185,389				364,856				246,198
Production			(15,259	)			(37,472	)			(21,504	)
Extensions and discoveries			10,573				40,330				17,295
Revisions of previous estimates			(33,730	)			(75,617	)			(46,333	)
Sales of reserves			(9,901	)			(13,554	)			(12,160	)
Proved reserves at June 30, 2015			137,072				278,543				183,496
Proved developed reserves
June 30, 2012			63,308				110,310				81,693
June 30, 2013			80,223				175,623				109,493
June 30, 2014			112,789				222,916				149,942
June 30, 2015			94,013				187,993				125,345
Proved undeveloped reserves
June 30, 2012			21,485				98,680				37,931
June 30, 2013			53,424				93,498				69,007
June 30, 2014			72,600				141,940				96,256
June 30, 2015			43,059				90,550				58,151

 

 

Our proved developed reserve estimates decreased by 24.6 MMBOE or 16% to 125.3 MMBOE at June 30, 2015 from 149.9 MMBOE at June 30, 2014. The decrease was primarily due to:

 

·

Downward revision of 12.8 MMBOE, primarily due to the effect of reduced oil and gas prices,

·

Divestiture of 11.7 MMBOE, and

·

Production of 21.5 MMBOE.

 

Offset by:

 

·

Additions of 8.5 MMBOE primarily from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from six fields: South Pass 78, Lomond North, West Delta 73, Main Pass 61, South Timbalier 54 and South Pass 49, and

·

Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves.

 

Our proved undeveloped reserve estimates decreased by 38.1 MMBOE or 40% to 58.2 MMBOE at June 30, 2015 from 96.3 MMBOE at June 30, 2014. The increase was primarily due to:

 

·

Downward revisions of 33.6 MMBOE comprised of (i) 7.3 MMBOE due to the effect of reduced oil and gas prices, (ii) 7.0 MMBOE due to certain wells that were no longer scheduled for development within five years, and (iii) 19.3 MMBOE due to new data and field studies. Of the 19.3 MMBOE of downward revisions due to new data and field studies, more than 80% occurred in the following seven fields:  Grand Isle 16, Ship Shoal 208, South Timbalier 21, South Timbalier 26, Vermilion 164, West Delta 30, and West Delta 73, and

·

Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves.

 

Offset by:

 

·

Additions of 8.8 MMBOE, primarily from additional drilling locations to make up for the lower throughput per well in West Delta 73, a replacement location at Bayou Carlin, and from the identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 73.

 

In the fiscal year ended June 30, 2015, we developed approximately 13.4% of our PUD reserves included in our June 30, 2014 reserve report, consisting of 21 gross, 21 net wells at a net cost of approximately $237 million.

 

We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors: including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report, with the exception of four locations totaling 3,560 MBOE or 6.1%. of our PUD reserves. These four locations are to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.

 

Standardized Measure of Discounted Future Net Cash Flows

 

Future cash inflows as of June 30, 2015 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $68.17 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12-month period ending on June 30, 2015). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $73.79 per barrel of oil and $29.54 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $73.79 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $68.17 per barrel (differential of $5.62 per barrel).

 

For natural gas, the average Henry Hub price used was $3.39 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $3.08 per Mcf after adjusting for energy content, transportation fees, and regional price differentials. 

 

 

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2015, 2014 and 2013 are as follows (in thousands):

 

		June 30,
		2015				2014				2013
Future cash inflows		$	10,641,151			$	20,162,506			$	15,048,978
Less related future
Production costs			4,131,526				5,500,669				3,657,595
Development and abandonment costs			1,970,526				2,959,994				1,838,159
Income taxes			168,655				2,546,155				2,591,351
Future net cash flows			4,370,444				9,155,688				6,961,873
Ten percent annual discount for estimated timing of cash flows			1,613,034				3,208,163				2,480,351
Standardized measure of discounted future net cash flows		$	2,757,410			$	5,947,525			$	4,481,522

 

Changes in Standardized Measure of Discounted Future Net Cash Flows

 

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows (in thousands):

 

		Year Ended June 30,
		2015				2014				2013
Beginning of year		$	5,947,525			$	4,481,522			$	3,305,489
Revisions of previous estimates
Changes in prices and costs			(2,959,883	)			(196,159	)			(106,002	)
Changes in quantities			(2,390,099	)			(389,570	)			635,562
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs			201,234				533,133				1,598,548
Purchases (sales) of reserves in place			(244,507	)			1,735,957				480,111
Accretion of discount			760,175				614,964				429,745
Sales, net of production and gathering and transportation costs			(676,949	)			(836,019	)			(842,268	)
Net change in income taxes			1,576,954				14,134				(676,158	)
Changes in rate of production			(191,668	)			(253,290	)			(456,254	)
Development costs incurred			237,173				247,865				125,925
Changes in estimated future development and abandonment costs and other			497,455				(5,012	)			(13,176	)
Net change			(3,190,115	)			1,466,003				1,176,033
End of year		$	2,757,410			$	5,947,525			$	4,481,522

 

 

Restated Unaudited Quarterly Financial Statements for the Three Months Ended September 30, 2014

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

(Unaudited)

 

		September 30,				June 30,
		2014				2014
		(Restated)				(Restated)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	—			$	9,325
Receivables:
Oil and natural gas sales			145,821				167,075
Joint interest billings			14,426				12,898
Insurance and other			3,348				4,099
Prepaid expenses and other current assets			60,311				69,367
Deferred income taxes			24,587				52,011
Derivative financial instruments			23,815				1,425
TOTAL CURRENT ASSETS			272,308				316,200
Property and Equipment
Oil and gas properties-net – full cost method of accounting, including $1,167.6 million and $1,165.7 million of unevaluated properties not being amortized at September 30, 2014 and June 30, 2014, respectively			6,542,079				6,427,263
Other property and equipment			2,868				3,087
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment			6,544,947				6,430,350
Other Assets
Goodwill			329,293				329,293
Note receivable from Energy XXI, Inc.			70,327				69,845
Derivative financial instruments			6,713				3,035
Restricted cash			325				6,350
Debt issuance costs, net of accumulated amortization			48,290				42,155
Total Other Assets			454,948				450,678
TOTAL ASSETS		$	7,272,203			$	7,197,228
LIABILITIES
CURRENT LIABILITIES
Accounts payable		$	472,825			$	416,576
Accrued liabilities			90,602				85,162
Notes payable			19,368				21,967
Asset retirement obligations			79,614				79,649
Derivative financial instruments			1,446				31,957
Current maturities of long-term debt			14,591				14,094
TOTAL CURRENT LIABILITIES			678,446				649,405
Long-term debt, less current maturities			3,449,750				3,396,473
Deferred taxes			651,871				657,687
Asset retirement obligations			482,339				480,185
Derivative financial instruments			—				4,306
Other liabilities			2,454				2,454
TOTAL LIABILITIES			5,264,860				5,190,510
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares authorized and 100,000 shares issued and outstanding			1				1
Additional paid-in capital			2,054,645				2,092,438
Accumulated deficit			(47,303	)			(85,721	)
TOTAL STOCKHOLDER’S EQUITY			2,007,343				2,006,718
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY		$	7,272,203			$	7,197,228

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

(Unaudited)

 

		Three Months Ended
		September 30,
		2014				2013
			(Restated)				(Restated)
Revenues
Oil sales		$	370,155			$	290,966
Natural gas sales			34,561				32,584
Gain (loss) on derivative financial instruments			56,725				(30,403	)
Total Revenues			461,441				293,147
Costs and Expenses
Lease operating expense			142,585				85,763
Production taxes			3,093				1,398
Gathering and transportation			9,188				5,345
Depreciation, depletion and amortization			158,402				96,905
Accretion of asset retirement obligation			12,819				7,326
General and administrative expense			14,993				21,329
Total Costs and Expenses			341,080				218,066
Operating Income			120,361				75,081
Other Income (Expense)
Interest income			464				483
Interest expense			(60,050	)			(29,604	)
Total Other Expense			(59,586	)			(29,121	)
Income Before Income Taxes			60,775				45,960
Income Tax Expense			21,607				16,087
Net Income		$	39,168			$	29,873

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

 

		Three Months Ended
		September 30,
		2014				2013
		(Restated)				(Restated)
Cash Flows from Operating Activities
Net income		$	39,168			$	29,873
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			158,402				96,905
Deferred income tax expense			21,607				16,087
Change in fair value of derivative financial instruments			(55,095	)			27,505
Accretion of asset retirement obligations			12,819				7,326
Amortization and write-off of debt issuance costs			2,159				1,455
Changes in operating assets and liabilities:
Accounts receivables			24,241				(2,238	)
Prepaid expenses and other current assets			9,056				(8,431	)
Asset retirement obligations			(14,907	)			(18,063	)
Accounts payable and other liabilities			47,130				(26,491	)
Net Cash Provided by Operating Activities			244,580				123,928
Cash Flows from Investing Activities
Acquisitions			(287	)			(15	)
Capital expenditures			(275,454	)			(197,369	)
Proceeds from the sale of properties			6,947				1,748
Net Cash Used in Investing Activities			(268,794	)			(195,636	)
Cash Flows from Financing Activities
Proceeds from long-term debt			510,120				1,040,697
Payments on long-term debt			(453,937	)			(865,128	)
Dividends to parent			(750	)			(82,000	)
Return to parent			(38,275	)			(13,126	)
Debt issuance costs			(2,269	)			(8,731	)
Other			—				(4	)
Net Cash Provided by Financing Activities			14,889				71,708
Net Decrease in Cash and Cash Equivalents			(9,325	)			—
Cash and Cash Equivalents, beginning of period			9,325				—
Cash and Cash Equivalents, end of period		$	—			$	—

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2014

(Unaudited)

 

Note 1 – Organization and Summary of Significant Accounting Policies

 

Nature of Operations. Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”).  Energy XXI Ltd (“Energy XXI”) indirectly owns 100% of Parent.  EGC (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, headquartered in Houston, Texas.  We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and offshore in the Gulf of Mexico.  References in this report to “us,” “we,” “our,” or “the Company,” are to EGC and its wholly-owned subsidiaries.

 

Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EGC and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation.

 

Interim Financial Statements. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended June 30, 2015 included herein.

 

Use of Estimates.   The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

 

Note 2 – Recent Accounting Pronouncements

 

In July 2013 the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU-2013-11”). ASU 2013-11 clarifies that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. We have no unrecognized tax benefits as defined in the literature; as such, issuance of ASU 2013-11 has no effect on our consolidated financial position, results of operations or cash flows.

  

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

 

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

 

Note 3 – Acquisitions and Dispositions

 

Black Elk Interest

 

On December 20, 2013, we closed on the acquisition of certain offshore Louisiana interests in West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for a total cash consideration of $10.4 million.  This acquisition was effective as of October 1, 2013.  We are the operator of these properties.

 

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013.  The acquisition of West Delta 30 Interests was accounted for under the acquisition method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 ( in thousands ):

 

Oil and natural gas properties – evaluated		$	15,821
Oil and natural gas properties – unevaluated			6,586
Asset retirement obligations			(10,503	)
Net working capital *			(1,500	)
Cash paid		$	10,404

 

* Net working capital includes payables.

 

Walter Oil & Gas Corporation oil and gas properties interests acquisition

 

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for a total cash consideration of approximately $22.8 million.  This acquisition was effective as of January 1, 2014 and we are the operator of these properties.

 

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014.  The acquisition of South Timbalier 54 Interests was accounted for under the acquisition method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 ( in thousands ):

 

Oil and natural gas properties – evaluated		$	23,497
Asset retirement obligations			(705	)
Cash paid		$	22,792

 

The fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

 

 

Apache Joint Venture

 

On February 1, 2013, we entered into an Exploration Agreement (the “Exploration Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central GoM Shelf.  We have a 25% participation interest in the Exploration Agreement, which expires on February 1, 2018.

   

The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area.  Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $33.7 million was incurred through September 30, 2014.  Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand.  In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands.  Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014.  As of September 30, 2014, our share of costs related to these wells was approximately $28.6 million.

 

Acquisition of EPL Oil & Gas, Inc. (“EPL”)

 

We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method.  Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

  

 In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash ("Cash Election"), or 1.669 shares of Energy XXI common stock ("Stock Election") or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock ("Mixed Election") and collectively the ("Merger Consideration"), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock.  Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share.  Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election.  In addition to the outstanding EPL shares shown below, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration.  As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, Energy XXI issued 23.3 million shares of its common stock and paid approximately $1,012 million in cash.

  

The following table summarizes the preliminary purchase price allocation for EPL as of June 3, 2014 (in thousands):

 

		EPL  Historical				Fair Value  Adjustment				Total
		(Unaudited)
Current assets (excluding deferred income taxes)		$	301,592			$	1,274			$	302,866
Oil and natural gas properties a
Evaluated (Including net ARO assets)			1,919,699				112,624				2,032,323
Unevaluated			41,896				859,886				901,782
Other property and equipment			7,787				-				7,787
Other assets			16,227				(9,002	)			7,225
Current liabilities (excluding ARO)			(314,649	)			(2,058	)			(316,707	)
ARO (current and long-term)			(260,161	)			(13,211	)			(273,372	)
Debt (current and long-term)			(973,440	)			(52,967	)			(1,026,407	)
Deferred income taxes b			(118,359	)			(340,645	)			(459,004	)
Other long-term liabilities			(2,242	)			797				(1,445	)
Total fair value, excluding  goodwill			618,350				556,698				1,175,048
Goodwill c,d			-				329,293				329,293
Less cash acquired			-				-				206,075
Total purchase price		$	618,350			$	885,991			$	1,298,266

 

 

a.   EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

b.  Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit).

c.  At September 30, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was unnecessary, and no goodwill impairment was recognized.

d.  On April 2, 2013, EPL sold certain shallow water GoM shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling to approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million.  This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million; accordingly the June 30, 2014 comparative information is retrospectively adjusted to increase the value of goodwill.

   

Costs associated with the EPL Acquisition totaled $13.6 million in the year ended June 30, 2014.  EPL’s operating revenues and net income of $174.1 million and $10.7 million for the quarter ended September 30, 2014 are included in the Consolidated Statements of Income for the quarter ended September 30, 2014.

 

In accordance with the acquisition method of accounting, the purchase price from our acquisition of EPL has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates, and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed has been recorded as goodwill. Goodwill recorded in connection with the acquisition is not deductible for income tax purposes.

 

The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.

 

The fair value measurements of the oil and natural gas properties and the asset retirement obligations included in other long-term liabilities were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value measurement of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.

 

Goodwill arose subsequent to the EPL Acquisition primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative functions by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, that enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets.

 

 

Sales of Oil and Natural Gas properties interests

 

On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of Energy XXI’s equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million.  Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014.  The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized.  The net reduction to the full cost pool related to this sale was $124.4 million.

 

On June 3, 2014, EXXI GOM, closed on the sale of its 100% interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary, for cash consideration of approximately $230 million.  As this transaction is between our two wholly owned indirect subsidiaries, there is no impact on a consolidated basis to our revenues and expenses or the full cost pool related to this transaction.

 

Note 4 – Property and Equipment

 

Property and equipment consists of the following (in thousands):

 

		September 30,				June 30,
		2014  (Restated)				2014  (Restated)
Oil and gas properties
Proved properties		$	8,518,475			$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment			3,144,033				2,985,790
Proved properties			5,374,442				5,261,562
Unevaluated properties			1,167,637				1,165,701
Oil and gas properties			6,542,079				6,427,263
Other property and equipment			3,213				3,173
Less: accumulated depreciation			345				86
Other property and equipment			2,868				3,087
Total property and equipment,  net of accumulated depreciation, depletion, amortization and impairment		$	6,544,947			$	6,430,350

 

The Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with unproved properties are transferred to evaluated properties upon the earlier of 1) when a determination is made whether there are any proved reserves related to the properties, or 2) amortized over a period of time of not more than four years.

 

Exploratory wells in progress include $197.7 million in costs related to our participation with Freeport-McMoRan, Inc. who operates several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico.  Activities related to certain of these well operations are controlled by the operator and these wells may have continued drilling and completion activities or, may require development of specialized equipment necessary to complete and test these wells for production.

 

As of September 30, 2014, the costs associated with our major projects and their status was as follows (in millions) :

 

Project Name		Cost				Status
Davy Jones Facilities		$	22.0			Facilities cost in Davy Jones field for well operations.
Davy Jones Offset Appraisal Well			70.2			Davy Jones Offset Appraisal Well is awaiting test of Wilcox sands.
Blackbeard East			51.4			Plans to complete into the Miocene Sands in late 2015.
Lomond North			54.1			Completion operations in progress to test lower Wilcox and Cretaceous objectives
Total		$	197.7

 

 

Note 5 – Long-Term Debt

 

Long-term debt consists of the following (in thousands):

 

		September 30,				June 30,
		2014				2014
Revolving credit facility		$	748,264			$	689,000
9.25% Senior Notes due 2017			750,000				750,000
8.25% Senior Notes due 2018			510,000				510,000
7.75% Senior Notes due 2019			250,000				250,000
7.5% Senior Notes due 2021			500,000				500,000
6.875% Senior Notes due 2024			650,000				650,000
Debt premium, 8.25% Senior Notes due 2018 (1)			38,033				40,567
Derivative instruments premium financing			18,044				21,000
Total debt			3,464,341				3,410,567
Less current maturities			14,591				14,094
Total long-term debt		$	3,449,750			$	3,396,473

 

(1) Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition.

 

Maturities of long-term debt as of September 30, 2014 are as follows (in thousands):

 

Twelve Months Ended September 30,
2015		$	14,591
2016			3,453
2017			—
2018			2,046,297
2019			250,000
Thereafter			1,150,000
Total		$	3,464,341

 

Revolving Credit Facility

 

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) in May 2011 and it underwent its Ninth Amendment on September 5, 2014. This facility, as amended, has a borrowing base of $1,500 million and lender commitments of $1,700 million and matures on April 9, 2018, provided that the facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017.  Borrowings are limited to a borrowing base based on oil and gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.  Under the First Lien Credit Agreement, we are allowed to pay Energy XXI a limited amount of distributions, subject to certain terms and conditions.  The First Lien Credit Agreement, as amended, requires us to maintain certain financial covenants. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our total leverage ratio to be more than 4.25 to 1.0 through the quarter ending March 31, 2015 and 4.0 to 1.0 from the quarter ending June 30, 2015 and beyond, (b) our interest coverage ratio to be less than 3.0 to 1.0, (c) our current ratio to be less than 1.0 to 1.0, and (d) our secured debt leverage ratio to be more than 1.75 to 1.0 through the quarter ending March 31, 2015 and 1.5 to 1.0 from the quarter ending June 30, 2015 and beyond (in each case as defined in our First Lien Credit Agreement). In addition, We are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

 

 

As of September 30, 2014, we were in compliance with all covenants and had $748.3 million in borrowings and $226 million in letters of credit issued under our First Lien Credit Agreement.

 

High Yield Facilities

 

8.25% Senior Notes Due 2018

 

On June 3, 2014, we assumed the 8.25% senior notes due 2018 (the “8.25% Senior Notes”) in the EPL Acquisition, which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”).  The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018.  On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL 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 Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the merger agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the consent time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked.  The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

 

We believe that the fair value of the $510 million of 8.25% Senior Notes outstanding as of September 30, 2014 was $519.1 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

  

6.875% Senior Notes Due 2024

 

On May 27, 2014, we issued $650 million face value of 6.875%, unsecured senior notes due March 15, 2024 at par (the “6.875% Senior Notes”).  Presently, the 6.875% Senior Notes are not registered under the Securities Act of 1933, as amended (the “Securities Act”), however we and our guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes.  We incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and will be amortized over the life of the 6.875% Senior Notes.

 

On or after March 15, 2019, we will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the Notes  remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We are required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 6.875% Senior Notes.

 

The indenture governing the 6.875% Senior Notes will, among other things, limits our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

 

We believe that the fair value of the $650 million of 6.875% Senior Notes outstanding as of September 30, 2014 was $617.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

 

7.5% Senior Notes Due 2021

 

On September 26, 2013, we issued $500 million face value of 7.5%, unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”).  In April 2014, we filed Amendment No. 1 to the registration statement for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes with the SEC.  The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014.  We incurred underwriting and direct offering costs of $8.6 million which have been capitalized and will be amortized over the life of the 7.5% Senior Notes.

 

On or after December 15, 2016, we will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, we may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, we may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We are required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.5% Senior Notes.

 

The indenture governing the 7.5% Senior Notes limits, among other things, our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

We believe that the fair value of the $500 million of 7.5% Senior Notes outstanding as of September 30, 2014 was $494.3 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

 

9.25% Senior Notes Due 2017

 

On December 17, 2010, we issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act, on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

 

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016.  The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised.  We incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

 

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of September 30, 2014 was $775.8 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

 

7.75% Senior Notes Due 2019

 

On February 25, 2011, we issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). It exchanged the full $250 million aggregate principal of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

 

 

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised.  We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

 

We have the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

 

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of September 30, 2014 was $250.4 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

 

Guarantee of Securities Issued by EGC

 

We are the issuer of each of the 6.875% Senior Notes, 7.5% Senior Notes, 9.25% Senior Notes and 7.75% Senior Notes, which are fully and unconditionally guaranteed by us and each of our existing and future material domestic subsidiaries other than EPL and its subsidiaries.  Energy XXI and its subsidiaries, other than us, do not have significant independent assets or operations. We are permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility.”

 

Derivative Instruments Premium Financing

 

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of September 30, 2014 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $18 million and $21 million, respectively.

 

Interest Expense

 

For the three months ended September 30, 2014 and 2013, interest expense consisted of the following ( in thousands ):

 

		Three Months Ended September 30,
		2014				2013
Revolving credit facility		$	6,893			$	5,219
9.25% Senior Notes due 2017			17,344				17,344
8.25% Senior Notes due 2018			10,519				-
7.75% Senior Notes due 2019			4,844				4,844
7.50% Senior Notes due 2021			9,375				521
6.875% Senior Notes due 2024			11,172				-
Amortization of debt issue cost - Revolving credit facility			977				806
Amortization of debt issue cost – 9.25% Senior Notes due 2017			552				552
Amortization of fair value premium – 8.25% Senior Notes due 2018			(2,534	)			-
Amortization of debt issue cost – 7.75% Senior Notes due 2019			97				97
Amortization of debt issue cost – 7.50% Senior Notes due 2021			263				-
Amortization of debt issue cost – 6.875% Senior Notes due 2024			281				-
Derivative instruments financing and other			267				221
		$	60,050			$	29,604

 

 

Note 6 – Notes Payable

 

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums.  The note was for a total face amount of $0.6 million and bore interest at an annual rate of 1.774%.  The note matured and was repaid on October 23, 2013.

 

In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million and bore interest at an annual rate of 1.623%. The note matured and was repaid on April 26, 2014.

 

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015.  The balance outstanding as of September 30, 2014 was $16.0 million.

 

On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015.  The balance outstanding as of September 30, 2014 was $3.4 million.

 

Note 7 – Asset Retirement Obligations

 

The following table describes the changes to our asset retirement obligations ( in thousands ):

 

Balance at June 30, 2014		$	559,834
Liabilities incurred			5,372
Liabilities settled			(14,907	)
Liabilities sold			(1,165	)
Accretion expense			12,819
Total balance at September 30, 2014			561,953
Less current portion			79,614
Long-term balance at September 30, 2014		$	482,339

 

Note 8 – Derivative Financial Instruments

 

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from the change in fair value from hedging transactions are recorded as gain (loss) on derivative financial instruments in earnings as a component of revenue in the consolidated statements of operations.

 

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

 

 

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.

 

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

 

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent.

 

As of September 30, 2014, we had the following net open crude oil derivative positions:

 

										Weighted Average Contract Price
										Swaps				Collars/Put Spreads
Period		Type of  Contract		Index		Volumes  (MBbls)				Fixed Price				Sub Floor				Floor				Ceiling
October 2014 - December 2014		Three-Way Collars		Oil-Brent-IPE			490							$	68.44			$	88.44			$	128.56
October 2014 - December 2014		Put Spreads		Oil-Brent-IPE			109								66.43				86.43
October 2014 - December 2014		Collars		Oil-Brent-IPE			184												90.00				108.38
October 2014 - December 2014		Put Spreads		NYMEX-WTI			310								70.00				90.00
October 2014 - December 2014		Three-Way Collars		NYMEX-WTI			610								70.00				90.00				137.20
October 2014 - December 2014		Swaps		ARGUS-LLS			712			$	91.95
January 2015 - December 2015		Three-Way Collars		Oil-Brent-IPE			3,650								71.00				91.00				113.75
January 2015 - December 2015		Swaps		Oil-Brent-IPE			548				97.70
January 2015 - December 2015		Collars		ARGUS-LLS			1,825												80.00				123.38
January 2015 - December 2015		Put Spreads		NYMEX-WTI			2,728												89.18

 

As of September 30, 2014, we had the following net open natural gas derivative positions:

 

Weighted Average Contract Price

Swaps

Collars/Put Spreads

Period

Type of  Contract

Index

Volumes  (MMBtu)

Fixed Price

Sub Floor

Floor

Ceiling

October 2014 - December 2014

Three-Way Collars

NYMEX-HH

4,197

$

3.36

$

4.00

$

4.60

October 2014 - December 2014

Put Spreads

NYMEX-HH

403

3.25

4.00

October 2014 - December 2014

Swaps

NYMEX-HH

460

$

4.01

January 2015 – December 2015

Swaps

NYMEX-HH

1,570

4.31

 

 

The fair values of derivative instruments in our consolidated balance sheets were as follows ( in thousands ):

 

		Asset Derivative Instruments												Liability Derivative Instruments
		September 30, 2014						June 30, 2014						September 30, 2014						June 30, 2014
		Balance Sheet  Location		Fair Value				Balance Sheet  Location		Fair Value				Balance Sheet  Location		Fair Value				Balance Sheet  Location		Fair Value
Derivative financial instruments		Current		$	31,138			Current		$	17,380			Current		$	8,769			Current		$	47,912
		Non-Current			9,110			Non-Current			9,595			Non-Current			2,397			Non-Current			10,866
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement					40,248						26,975						11,166						58,778
Derivative financial instruments		Current			(7,323	)		Current			(15,955	)		Current			(7,323	)		Current			(15,955	)
		Non-Current			(2,397	)		Non-Current			(6,560	)		Non-Current			(2,397	)		Non-Current			(6,560	)
Gross amounts offset in Balance Sheets					(9,720	)					(22,515	)					(9,720	)					(22,515	)
Net amounts presented in Balance Sheets		Current			23,815			Current			1,425			Current			1,446			Current			31,957
		Non-Current			6,713			Non-Current			3,035			Non-Current			—			Non-Current			4,306
				$	30,528					$	4,460					$	1,446					$	36,263

 

The effect of derivative instruments on our consolidated statements of income was as follows (in thousands):

 

		Three Months Ended September 30,
Gain (loss) on derivative financial instruments		2014				2013
Cash Settlements, net of amortization of purchased put premiums		$	(1,734	)		$	(2,898	)
Proceeds from monetizations, net			3,364				-
Change in fair value			55,095				(27,505	)
Total gain (loss) on derivative financial instruments		$	56,725			$	(30,403	)

 

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At September 30, 2014, we had no deposits for collateral with our counterparties.

 

Note 9 – Income Taxes

 

We are a (U.S.) Delaware company and a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI, Inc., (the “U.S. Parent”) is the parent entity.  Energy XXI indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group.  We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon the tax laws and rates of the United States as they apply to our current ownership structure. ASC Topic 740 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated financial reporting group should be based upon a reasonable allocation of the income tax amounts of that group.  We allocate income tax expense and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the year-to-date reporting period.  We have recorded no income tax related intercompany balances with affiliates. 

 

 

We have a remaining valuation allowance of $22.5 million related to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more likely-than-not basis, are realizable due to our current focus on offshore operations.  While the U.S. consolidated group historically has paid no (significant) cash taxes, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required.  We are a party to an intercompany agreement whereby we would be responsible for funding consolidated U.S. federal income tax payments.  We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

 

Note 10 – Supplemental Cash Flow Information

 

The following table represents our supplemental cash flow information (in thousands):

 

		Three Months Ended September 30,
		2014				2013
Cash paid for interest		$	41,758			$	5,696
Cash paid for income taxes			280				2,856

 

The following table represents our non-cash investing and financing activities (in thousands):

 

		Three Months Ended September 30,
		2014				2013
Financing of insurance premiums		$	3,358			$	2,355
Derivative instruments premium financing			-				698
Additions to property and equipment by recognizing asset retirement obligations			4,207				14,151

 

Note 11 – Related Party Transactions

 

During the three months ended September 30, 2014 and 2013, we paid dividends of $0.8 million and $82 million, respectively, to our Parent.  During the three months ended September 30, 2014 and 2013, we returned net capital contributions of $38.3 million and $13.1 million, respectively, to our Parent.

 

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc. our indirect parent, bearing a simple interest of 2.78% per annum.  The note matures on December 16, 2021.  Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium.  Interest and principal are payable at maturity.  Interest on the note receivable amounted to approximately $482,000 and $481,000 for the three months ended September 30, 2014 and 2013, respectively.  Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of September 30, 2014.

 

We reimbursed $3.6 million to our affiliate Energy XXI Insurance Limited for windstorm insurance coverage.  The coverage is for period from June 1, 2014 through June 1, 2015.

 

We have no employees; instead we receive management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company.  Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services.  Cost of these services for both the three months ended September 30, 2014 and 2013 was approximately $4.6 million and $21.6 million, and is included in general and administrative expense.

 

 

Prior to the LLOG Exploration acquisition, we received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the three months ended September 30, 2014 and 2013, we received management fees of $0.9 million and $0.7 million, respectively.

 

On April 1, 2014, EXXI GOM closed on sale of its interest in Eugene Island 330 and South Marsh Island 128 properties to M21K and on June 3, 2014, it closed on the sale of its 100% interests in South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Quarterly Report.

 

Note 12 – Commitments and Contingencies

 

Litigation.   We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.

 

Litigation Related to Merger.   In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against the Company, EPL, its directors, and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014.  The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

 

Plaintiffs allege a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provides for the acquisition of EPL by Energy XXI. Plaintiffs allege that (a) EPL’s directors have allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL have allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on their allegations that (i) the merger allegedly provided inadequate consideration to EPL stockholders for their shares of EPL common stock; (ii) the merger agreement contains contractual terms — including, among others, the (A) “no solicitation,” (B) “competing proposal,” and (C) “termination fee” provisions — that allegedly dissuaded other potential acquirers from making competing offers for shares of EPL common stock; (iii) certain of EPL’s officers and directors allegedly received benefits — including (A) an offer for one of EPL’s directors to join the Energy XXI board of directors and (B) the triggering of change-in-control provisions in notes held by EPL’s executive officers — that were not equally shared by EPL’s stockholders; (iv) Energy XXI required EPL’s officers and directors to agree to vote their shares of EPL common stock in favor of the merger; and (v) EPL provided, and Energy XXI obtained, non-public information that allegedly allowed Energy XXI to acquire EPL for inadequate consideration. Plaintiffs also allege that the Registration Statement filed on Form S-4 by EPL and Energy XXI on April 1, 2014 omits information concerning, among other things, (i) the events leading up to the merger, (ii) EPL’s efforts to attract offers from other potential acquirors, (iii) EPL’s evaluation of the merger; (iv) negotiations between EPL and Energy XXI, and (v) the analysis of EPL’s financial advisor. Based on these allegations, plaintiffs seek to have the merger agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

 

Defendants date to answer, move to dismiss, or otherwise respond to the lawsuit has been indefinitely extended. Neither Energy XXI nor EPL can predict the outcome of the lawsuit or any others that might be filed subsequent to the date of the filing of this quarterly report; nor can either Energy XXI or EPL predict the amount of time and expense that will be required to resolve the lawsuit. The defendants intend to vigorously defend the lawsuit.

 

Letters of Credit and Performance Bonds.   We had $226 million in letters of credit and $170.5 million of performance bonds outstanding as of September 30, 2014.

 

Drilling Rig Commitments.  The drilling rig commitments represent minimum future expenditures for drilling rig services.  The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of September 30, 2014, we have the following drilling rig commitments;

 

1)  April 10, 2014 to October 27, 2014 at $54,448 per day

 

2)  September 1, 2013 to November 30, 2014 at $130,000 per day

 

 

3)  March 10, 2014 to March 9, 2015 at $53,175 per day

 

4)  February 15, 2014 to December 29, 2014 at $111,380 per day

 

5)  April 11, 2014 to October 12, 2014 at $112,000 per day

 

6)  July 1, 2014 to October 21, 2014 at $107,500 per day.

 

7)  October 4, 2014 to November 4, 2014 at $107,500 per day.

 

At September 30, 2014, future minimum commitments under these contracts totaled $34.8 million.

 

Note 13 — Fair Value of Financial Instruments

 

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

 

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

 

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 8 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

 

Valuation techniques are generally classified into three categories: the market approach, the income approach and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

  

•

Level 1 – quoted prices in active markets for identical assets or liabilities.

 

•

Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

 

•

Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

 

The following table presents the fair value of our Level 2 financial instruments (in thousands):

 

		Level 2
		As of September 30,				As of June  30,
		2014				2014
Assets:
Oil and natural gas derivatives		$	40,248			$	26,975
Liabilities:
Oil and natural gas derivatives		$	11,166			$	58,778

 

 

Note 14 — Prepayments and Accrued Liabilities

 

Prepayments and accrued liabilities consist of the following (in thousands):

 

		September 30,				June 30,
		2014				2014
Prepaid expenses and other current assets
Advances to joint interest partners		$	10,821			$	10,336
Insurance			28,278				36,451
Inventory			7,168				7,020
Royalty deposit			11,832				12,262
Other			2,212				3,298
Total prepaid expenses and other current assets		$	60,311			$	69,367
Accrued liabilities
Advances from joint interest partners		$	2,831			$	2,667
Interest payable			44,692				26,490
Accrued hedge payable			1,761				7,874
Undistributed oil and gas proceeds			31,345				34,473
Severance taxes payable			2,021				8,014
Other			7,952				5,644
Total accrued liabilities		$	90,602			$	85,162

 

Note 15 — Subsequent Event

 

In October 2014 and in November 2014, we monetized certain WTI put contracts and certain Brent swap contracts related to calendar year 2015 and realized $21.3 million and $7.5 million, respectively.  These monetized amounts will be recorded in stockholder’s equity as part of OCI and will be recognized in income over the contract life of the underlying hedge contracts during calendar year 2015.

 

Note 16 — Restatement of Previously Issued Consolidated Financial Statements

 

In connection with preparing our Consolidated Financial Statements for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging.  The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment.  Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings.  Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.

 

The effects of the restatement on our consolidated financial statements are summarized below:

 

·

Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue;

·

Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue;

 

 

·

Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and

·

Resulting adjustments required to deferred income taxes and income tax expense (benefit).

 

While these non-cash reclassifications impact revenues and net income (loss) in each period, as well as total stockholder’s equity, they have no material impact on cash flows. Details of the restatement applicable to these quarterly consolidated financial statements are as follows:

 

		As of September 30, 2014												As of June 30, 2014
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands)
Total Current Assets		$	272,308			$	-			$	272,308			$	316,200			$	-			$	316,200
Property and Equipment
Oil and natural gas properties, net			6,637,292				(95,213	)			6,542,079				6,524,602				(97,339	)			6,427,263
Other property and equipment			2,868				-				2,868				3,087				-				3,087
Total Property and Equipment, net			6,640,160				(95,213	)			6,544,947				6,527,689				(97,339	)			6,430,350
Total Other Assets			454,948				-				454,948				450,678				-				450,678
Total Assets		$	7,367,416			$	(95,213	)		$	7,272,203			$	7,294,567			$	(97,339	)		$	7,197,228
Total Current Liabilities		$	678,446			$	-			$	678,446			$	649,405			$	-			$	649,405
Deferred Income Taxes			685,218				(33,347	)			651,871				691,779				(34,092	)			657,687
Other Non-Current Liabilities			3,934,543				-				3,934,543				3,883,418				-				3,883,418
Total Liabilities			5,298,207				(33,347	)			5,264,860				5,224,602				(34,092	)			5,190,510
Stockholder’s Equity
Common stock			1				-				1				1				-				1
Additional paid-in capital			2,054,645				-				2,054,645				2,092,428				-				2,092,438
Accumulated deficit			(706	)			(46,597	)			(47,303	)			(2,040	)			(83,681	)			(85,721	)
Accumulated other comprehensive loss, net of income taxes			15,269				(15,269	)			-				(20,434	)			20,434				-
Total Stockholder’s Equity			2,069,209				(61,866	)			2,007,343				2,069,965				(63,247	)			2,006,718
Total Liabilities and Stockholder’s Equity		$	7,367,416			$	(95,213	)		$	7,272,203			$	7,294,567			$	(97,339	)		$	7,197,228

 

 

		Three Months Ended September 30, 2014												Three Months Ended September 30, 2013
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands, except share information)
Revenues
Crude oil sales		$	368,501			$	1,654			$	370,155			$	289,229			$	1,737			$	290,966
Natural gas sales			34,730				(169	)			34,561				35,363				(2,779	)			32,584
Gain (loss) on derivative financial instruments			-				56,725				56,725				-				(30,403	)			(30,403	)
Total Revenues			403,231				58,210				461,441				324,592				(31,445	)			293,147
Costs and Expenses
Depreciation, depletion and amortization			160,528				(2,126	)			158,402				99,462				(2,557	)			96,905
(Gain) loss on derivative financial instruments			(3,283	)			3,283				-				1,441				(1,441	)			-
All other costs and expenses			182,678				-				182,678				121,161				-				121,161
Total Costs and Expenses			339,923				1,157				341,080				222,064				(3,998	)			218,066
Operating Income			63,308				57,053				120,361				102,528				(27,447	)			75,081
Other Income (Expense)
Other income, net			464				-				464				483				-				483
Interest expense			(60,050	)			-				(60,050	)			(29,604	)			-				(29,604	)
Total Other Expense, net			(59,586	)			-				(59,586	)			(29,121	)			-				(29,121	)
Income (Loss) Before Income Taxes			3,722				57,053				60,775				73,407				(27,447	)			45,960
Income Tax Expense (Benefit)			1,638				19,969				21,607				25,693				(9,606	)			16,087
Net Income (Loss)			2,084				37,084				39,168				47,714				(17,841	)			29,873
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			56,916				(56,916	)			-				(22,656	)			22,656				-
Effective portion reclassified to earnings during the period			(1,988	)			1,988				-				(7,348	)			7,348				-
Total Other Comprehensive Loss			54,928				(54,928	)			-				(30,004	)			30,004				-
Income Tax Expense (Benefit)			19,225				(19,225	)			-				(10,501	)			10,501
Net Other Comprehensive Income (Loss)			35,703				(35,703	)			-				(19,503	)			19,503				-
Comprehensive Income		$	37,787			$	1,381			$	39,168			$	28,211			$	1,662			$	29,873

 

 

		Three Months Ended September 30, 2014												Three Months Ended September 30, 2013
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands)
Cash Flows From Operating Activities
Net income (loss)		$	2,084			$	37,084			$	39,168			$	47,714			$	(17,841	)		$	29,873
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			160,528				(2,126	)			158,402				99,462				(2,557	)			96,905
Deferred income tax expense (benefit)			(1,638	)			19,969				21,607				25,693				(9,606	)			16,087
Change in fair value of derivative financial instruments			(2,574	)			(52,521	)			(55,095	)			(2,356	)			29,861				27,505
Accretion of asset retirement obligations			12,819				-				12,819				7,326				-				7,326
Amortization and write-off of debt issuance costs and other			2,159				-				2,159				1,455				-				1,455
Changes in operating assets and liabilities
Accounts receivable			24,241				-				24,241				(2,238	)			-				(2,238	)
Prepaid expenses and other current assets			9,056				-				9,056				(8,431	)			-				(8,431	)
Settlement of asset retirement obligations			(14,907	)			-				(14,907	)			(18,063	)			-				(18,063	)
Accounts payable and accrued liabilities			49,536				(2,406	)			47,130				(26,634	)			143				(26,491	)
Net Cash Provided by Operating Activities			244,580				-				244,580				123,928				-				123,928
Net Cash Used in Investing Activities			(268,794	)			-				(268,794)				(195,636	)			-				(195,636)
Net Cash Provided by Financing Activities			14,889				-				14,889				71,708				-				71,708
Net Increase (Decrease) in Cash and Cash Equivalents			(9,325	)			-				(9,325	)			-				-				-
Cash and Cash Equivalents, beginning of period			9,325								9,325				-								-
Cash and Cash Equivalents, end of period		$	-							$	-			$	-							$	-

 

 

Restated Unaudited Quarterly Financial Statements for the Three and Six Months Ended December 31, 2014

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

(Unaudited)

 

		December 31,				June 30,
		2014				2014
		(Restated)				(Restated)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	—			$	9,325
Accounts receivable
Oil and natural gas sales			102,882				167,075
Joint interest billings			19,098				12,898
Other			28,971				4,099
Prepaid expenses and other current assets			46,204				69,367
Deferred income taxes			11,235				52,011
Derivative financial instruments			150,026				1,425
TOTAL CURRENT ASSETS			358,416				316,200
Property and Equipment
Oil and gas properties, net – full cost method of accounting, including $807.8 million and $1,165.7 million of unevaluated properties not being amortized at December 31, 2014 and June 30, 2014, respectively			6,549,530				6,427,263
Other property and equipment, net			2,627				3,087
Total Property and Equipment, net of accumulated depreciation,  depletion, amortization and impairment			6,552,157				6,430,350
Other Assets
Goodwill			—				329,293
Note receivable from Energy XXI, Inc.			70,808				69,845
Derivative financial instruments			8,377				3,035
Restricted cash			6,024				6,350
Debt issuance costs, net of accumulated amortization			40,037				42,155
Total Other Assets			125,246				450,678
TOTAL ASSETS		$	7,035,819			$	7,197,228
LIABILITIES
CURRENT LIABILITIES
Accounts payable		$	313,137			$	416,576
Accrued liabilities			68,837				85,162
Notes payable			12,175				21,967
Asset retirement obligations			79,573				79,649
Derivative financial instruments			—				31,957
Current maturities of long-term debt			20,752				14,094
TOTAL CURRENT LIABILITIES			494,474				649,405
Long-term debt, less current maturities			3,636,771				3,396,473
Deferred income taxes			668,661				657,687
Asset retirement obligations			470,523				480,185
Derivative financial instruments			—				4,306
Other liabilities			5,332				2,454
TOTAL LIABILITIES			5,275,761				5,190,510
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares authorized and 100,000 shares issued and outstanding			1				1
Additional paid-in capital			2,072,556				2,092,438
Accumulated deficit			(312,499	)			(85,721	)
TOTAL STOCKHOLDER’S EQUITY			1,760,058				2,006,718
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY		$	7,035,819			$	7,197,228

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

 CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands)

(Unaudited)

 

		Three Months Ended								Six Months Ended
		December 31,								December 31,
		2014				2013				2014				2013
		(Restated)				(Restated)				(Restated)				(Restated)
Revenues
Oil sales		$	279,708			$	263,627			$	649,863			$	554,593
Natural gas sales			31,801				31,138				66,362				63,722
Gain (loss) on derivative financial instruments			191,462				(20,951	)			248,187				(51,354	)
Total Revenues			502,971				273,814				964,412				566,961
Costs and Expenses
Lease operating			119,366				93,789				261,951				179,552
Production taxes			2,263				1,189				5,356				2,587
Gathering and transportation			4,771				5,978				13,959				11,323
Depreciation, depletion and amortization			174,341				100,153				332,743				197,058
Accretion of asset retirement obligations			12,798				7,425				25,617				14,751
Goodwill impairment			329,293				—				329,293				—
General and administrative expense			35,045				15,163				50,038				36,492
Total Costs and Expenses			677,877				223,697				1,018,957				441,763
Operating Income (Loss)			(174,906	)			50,117				(54,545	)			125,198
Other Income (Expense)
Other income, net			490				487				954				970
Interest expense			(60,637	)			(35,837	)			(120,687	)			(65,441	)
Total Other Expense			(60,147	)			(35,350	)			(119,733	)			(64,471	)
Income (Loss) Before Income Taxes			(235,053	)			14,767				(174,278	)			60,727
Income Tax Expense (Benefit)			30,143				5,178				51,750				21,265
Net Income (Loss)		$	(265,196	)		$	9,589			$	(226,028	)		$	39,462

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

 

		Six Months Ended
		December 31,
		2014 (Restated)				2013 (Restated)
Cash Flows from Operating Activities
Net income (loss)		$	(226,028	)		$	39,462
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense (benefit)			51,750				21,265
Change in fair value of derivative financial instruments			(175,731	)			46,655
Accretion of asset retirement obligations			25,617				14,751
Depreciation, depletion and amortization			332,743				197,058
Goodwill impairment			329,293				—
Amortization of debt issuance costs and other			(683	)			3,250
Changes in operating assets and liabilities:
Accounts receivables			34,237				16,870
Prepaid expenses and other current assets			23,163				(5,111	)
Settlement of asset retirement obligations			(53,960	)			(34,038	)
Accounts payable and other liabilities			(142,517	)			(35,906	)
Net Cash Provided by Operating Activities			197,884				264,256
Cash Flows from Investing Activities
Acquisitions			(287	)			(12,564	)
Capital expenditures			(442,606	)			(386,979	)
Transfer from (to) restricted cash			326				(746	)
Proceeds from the sale of properties			6,947				1,748
Net Cash Used in Investing Activities			(435,620	)			(398,541	)
Cash Flows from Financing Activities
Dividends to parent			(750	)			(150,100	)
Proceeds from long-term debt			1,011,948				1,428,117
Payments on long-term debt			(759,639	)			(1,127,673	)
Advance to Energy XXI, Inc.			(963	)			(963	)
Returns to parent			(19,882	)			(5,158	)
Debt issuance costs and other			(2,303	)			(9,938	)
Net Cash Provided by Financing Activities			228,411				134,285
Net Decrease in Cash and Cash Equivalents			(9,325	)			—
Cash and Cash Equivalents, beginning of period			9,325				—
Cash and Cash Equivalents, end of period		$	—			$	—

 

See accompanying Notes to Consolidated Financial Statements

  

 

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2014

(UNAUDITED)

 

Note 1 — Basis of Presentation

 

Nature of Operations. Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”).  References in this report to “us,” “we,” “our,” or “the Company,” are to EGC and its wholly-owned subsidiaries.  Energy XXI Ltd (“Energy XXI”) indirectly owns 100% of Parent.  EGC (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, headquartered in Houston, Texas.  We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and offshore in the Gulf of Mexico.

 

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of EGC and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

 

Interim Financial Statements. The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended June 30, 2015 included herein.

 

Use of Estimates.   The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value of estimates used in accounting for acquisitions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others.   Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates.  While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.

 

Note 2 – Recent Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual periods beginning after December 15, 2016, and interim periods within those annual reporting periods. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

 

  

Note 3 – Acquisitions and Dispositions

 

Black Elk Interest

 

On December 20, 2013, we acquired certain offshore Louisiana interests in the West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for total cash consideration of $10.4 million.  This acquisition was effective as of October 1, 2013, and we are the operator of these properties.

 

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 ( in thousands ):

 

Oil and natural gas properties – evaluated		$	15,821
Oil and natural gas properties – unevaluated			6,586
Asset retirement obligations			(10,503	)
Net working capital *			(1,500	)
Cash paid		$	10,404

 

* Net working capital includes payables.

 

Walter Oil & Gas Corporation Oil and Gas Properties Interests

 

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for total cash consideration of approximately $22.8 million.  This acquisition was effective as of January 1, 2014 and we are the operator of these properties.

 

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 ( in thousands ):

 

Oil and natural gas properties – evaluated		$	23,497
Asset retirement obligations			(705	)
Cash paid		$	22,792

 

We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates.  In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.  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 14 - Fair Value Measurements.

 

EPL Oil & Gas, Inc. (“EPL”)

 

We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method.  Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

 

 

In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election”) and collectively the (“Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock.  Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share.  Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election.  In addition to the outstanding EPL shares, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration.  As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 per share in cash, without proration.    Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of our common stock and paid approximately $1,012 million in cash.

 

The following table summarizes the preliminary purchase price allocation for the EPL Acquisition as of June 3, 2014 (in thousands):

 

		EPL Historical				Fair Value Adjustment				Total
						(Unaudited)
Current assets (excluding deferred income taxes)		$	301,592			$	1,274			$	302,866
Oil and natural gas properties a
Evaluated (Including net ARO assets)			1,919,699				112,624				2,032,323
Unevaluated			41,896				859,886				901,782
Other property and equipment			7,787				—				7,787
Other assets			16,227				(9,002	)			7,225
Current liabilities (excluding ARO)			(314,649	)			(2,058	)			(316,707	)
ARO (current and long-term)			(260,161	)			(13,211	)			(273,372	)
Debt (current and long-term)			(973,440	)			(52,967	)			(1,026,407	)
Deferred income taxes b			(118,359	)			(340,645	)			(459,004	)
Other long-term liabilities			(2,242	)			797				(1,445	)
Total fair value, excluding  goodwill			618,350				556,698				1,175,048
Goodwill c,d			—				329,293				329,293
Less cash acquired			—				—				206,075
Total purchase price		$	618,350			$	885,991			$	1,298,266

 

a.      EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

 

b.      Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit).

 

c.      See Note 4 - Goodwill for more information regarding goodwill impairment at December 31, 2014.

 

d.     On April 2, 2013, EPL sold certain shallow water Gulf of Mexico (“GoM”) Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million.  This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million; accordingly the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill.

 

In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates; and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.

 

 

The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.

 

The fair value estimates of the oil and natural gas properties and the asset retirement obligations were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value estimate of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.

 

The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, that enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets.  During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.   See Note 4 - Goodwill for more information regarding the impairment of goodwill at December 31, 2014.

 

In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred.  EPL’s operating revenues and net loss of $156.6 million and $326.2 million for the quarter ended December 31, 2014 are included in the Consolidated Statement of Operations for the quarter ended December 31, 2014.  EPL’s operating revenues and net loss of $330.7 million and $315.5 million for the six months ended December 31, 2014 are included in the Consolidated Statement of Operations for the six months ended December 31, 2014.

 

The following supplemental unaudited pro forma financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on ours and EPL’s historical consolidated statements of income for the three and six months ended December 31, 2013 ( in thousands ).

 

		Three Months Ended December 31, 2013 (Restated)				Six Months Ended December 31, 2013 (Restated)
Revenues		$	424,053			$	919,430
Net income (loss)			(15,496	)			5,170

 

The above supplemental unaudited pro forma financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments for the three and six months ended December 31, 2013, were the following:

 

a.

Exclude $13.6 million and $17.0 million, respectively, of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with our full cost method of accounting.

 

b.

Increase DD&A expense by $26.7 million and $45.1 million, respectively, for the EPL properties to correspond with our full cost method of accounting.

 

c.

Increase interest expense by $13.1 million and $26.2 million, respectively, to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under our revolving credit facility. Decrease interest expense $3.3 million and $6.6 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million face value of EPL’s 8.25% Senior Notes assumed in the EPL acquisition.

 

 

Sales of Oil and Natural Gas properties interests

 

On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of Energy XXI’s equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million.  Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014.  The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized.  The net reduction to the full cost pool related to this sale was $124.4 million.

 

On June 3, 2014, EXXI GOM, closed on the sale of its 100% interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary, for cash consideration of approximately $230 million.  As this transaction is between our two wholly owned indirect subsidiaries, there is no impact on a consolidated basis to our revenues and expenses or the full cost pool related to this transaction.

 

Note 4 – Goodwill

 

ASC 350, Intangibles—Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment.  Our annual goodwill impairment test is performed as of the last day of the fourth quarter each fiscal year.

 

Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.

 

At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves.  Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill.  As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.

 

In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using a weighted average cost of capital. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs.  The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.

 

 

Note 5 – Property and Equipment

 

Property and equipment consists of the following ( in thousands ):

 

		December 31,				June 30,
		2014 (Restated)				2014 (Restated)
Oil and gas properties
Proved properties		$	9,059,934			$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment			3,318,218				2,985,790
Proved properties, net			5,741,716				5,261,562
Unevaluated properties			807,814				1,165,701
Oil and gas properties, net			6,549,530				6,427,263
Other property and equipment			3,231				3,173
Less: accumulated depreciation			604				86
Other property and equipment, net			2,627				3,087
Total property and equipment,  net of accumulated depreciation, depletion, amortization and impairment		$	6,552,157			$	6,430,350

 

The Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL acquisition), exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) amortization over a period of time of not more than four years.

 

At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties.  Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following:  1) the Lomond North project resulted in a successful production test with commercial production expected to commence in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the Blackbeard East project expired.  Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the quarter ended December 31, 2014.

 

Note 6 – Long-Term Debt

 

Long-term debt consists of the following ( in thousands ):

 

		December 31,				June 30,
		2014				2014
Revolving Credit Facility		$	941,309			$	689,000
9.25% Senior Notes due 2017			750,000				750,000
8.25% Senior Notes due 2018			510,000				510,000
7.75% Senior Notes due 2019			250,000				250,000
7.5% Senior Notes due 2021			500,000				500,000
6.875% Senior Notes due 2024			650,000				650,000
Debt premium, 8.25% Senior Notes due 2018 (1)			35,462				40,567
Derivative instruments premium financing			20,752				21,000
Total debt			3,657,523				3,410,567
Less current maturities			20,752				14,094
Total long-term debt		$	3,636,771			$	3,396,473

  

(1)	Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition.

 

 

Maturities of long-term debt as of December 31, 2014 are as follows (in thousands):

 

Twelve Months Ended December 31,

 

2015		$	20,752
2016			—
2017			750,000
2018			1,486,771
2019			250,000
Thereafter			1,150,000
Total		$	3,657,523

 

Revolving Credit Facility

 

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility”) in May 2011 and it underwent its Ninth Amendment on September 5, 2014. This facility, as amended, has a borrowing base of $1,500 million and lender commitments of $1,700 million and matures on April 9, 2018, provided that the facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base based on oil and gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The Revolving Credit Facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, we are allowed to pay Energy XXI a limited amount of distributions, subject to certain terms and conditions.

 

The First Lien Credit Agreement, as amended, requires us to maintain certain financial covenants. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our total leverage ratio to be more than 4.25 to 1.0 through the quarter ending March 31, 2015 and 4.0 to 1.0 from the quarter ending June 30, 2015 and beyond, (b) our interest coverage ratio to be less than 3.0 to 1.0, (c) our current ratio to be less than 1.0 to 1.0, and (d) our secured debt leverage ratio to be more than 1.75 to 1.0 through the quarter ending March 31, 2015 and 1.5 to 1.0 from the quarter ending June 30, 2015 and beyond (in each case as defined in the First Lien Credit Agreement). In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

 

As of December 31, 2014, we were in compliance with all covenants and had $941.3 million in borrowings and $226.3 million in letters of credit issued under the First Lien Credit Agreement.  Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with certain covenants under this agreement in certain future periods.  We are focused on reducing our leverage and are pursuing arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable us to further reduce the amount of required capital commitments.  We are also evaluating various alternatives with respect to the First Lien Credit Agreement, including other sources of financing, although any such alternative sources of financing likely would be at higher cost than our current Revolving Credit Facility.  There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility.  Certain payment defaults or an acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

 

 

8.25% Senior Notes Due 2018

 

On June 3, 2014, we assumed the 8.25% senior notes due 2018 (the “8.25% Senior Notes”) in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018.  On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL's obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

 

6.875% Senior Notes Due 2024

 

On May 27, 2014, we issued $650 million face value of 6.875% unsecured senior notes due March 15, 2024 at par (the “6.875% Senior Notes”).  Presently, the 6.875% Senior Notes are not registered under the Securities Act of 1933, as amended (the “Securities Act”).  However, we and our guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes.  On November 25, 2014, we filed a registration statement with the SEC for an offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. The registration statement was not yet declared effective by the SEC as of January 30, 2015.  we incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and are being amortized over the life of the 6.875% Senior Notes.

 

On or after March 15, 2019, we will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the 6.875% Senior Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, we may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We are required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.

 

The indenture governing the 6.875% Senior Notes, among other things, limits our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

7.5% Senior Notes Due 2021

 

On September 26, 2013, we issued $500 million face value of 7.5% unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”).  In April 2014, we filed Amendment No. 1 to the registration statement with the SEC for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014.  We incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.

 

 

On or after December 15, 2016, we will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, we may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, we may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We are required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.

 

The indenture governing the 7.5% Senior Notes limits, among other things, our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

7.75% Senior Notes Due 2019

 

On February 25, 2011, we issued $250 million face value of 7.75% unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). It exchanged the full $250 million aggregate principal amount of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

 

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.

 

9.25% Senior Notes Due 2017

 

On December 17, 2010, we issued $750 million face value of 9.25% unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal amount of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

 

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. We incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.

 

Derivative Instruments Premium Financing

 

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of December 31, 2014 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $20.8 million and $21.0 million, respectively.

 

 

Interest Expense

 

For the three and six months ended December 31, 2014 and 2013, interest expense consisted of the following ( in thousands ):

 

		Three Months Ended								Six Months Ended
		December 31,								December 31,
		2014				2013				2014				2013
Revolving Credit Facility		$	7,482			$	2,326			$	14,375			$	7,545
9.25% Senior Notes due 2017			17,344				17,344				34,688				34,688
8.25% Senior Notes due 2018			10,519				—				21,038				—
7.75% Senior Notes due 2019			4,844				4,844				9,688				9,688
7.50% Senior Notes due 2021			9,375				9,271				18,750				9,792
6.875% Senior Notes due 2024			11,172				—				22,344				—
Amortization of debt issue cost – Revolving Credit Facility			1,080				855				2,057				1,661
Amortization of debt issue cost – 9.25% Senior Notes due 2017			551				552				1,103				1,104
Amortization of fair value premium – 8.25% Senior Notes due 2018			(2,570	)			—				(5,104	)			—
Amortization of debt issue cost – 7.75% Senior Notes due 2019			97				97				194				194
Amortization of debt issue cost – 7.50% Senior Notes due 2021			262				260				525				260
Amortization of debt issue cost – 6.875% Senior Notes due 2024			282				—				563				—
Derivative instruments financing and other			199				288				466				509
		$	60,637			$	35,837			$	120,687			$	65,441

 

Note 7 – Notes Payable

 

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015.  The balance outstanding as of December 31, 2014 was $10.0 million.

 

On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015.  The balance outstanding as of December 31, 2014 was $2.2 million.

 

Note 8 – Asset Retirement Obligations

 

The following table describes the changes to our asset retirement obligations (in thousands):

 

Balance at June 30, 2014		$	559,834
Liabilities incurred and true-up to liabilities settled			21,912
Liabilities settled			(53,960	)
Liabilities sold			(3,307	)
Accretion expense			25,617
Total balance at December 31, 2014			550,096
Less current portion			79,573
Long-term balance at December 31, 2014		$	470,523

 

Note 9 – Derivative Financial Instruments

 

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from the change in fair value from hedging transactions are recorded as gain (loss) on derivative financial instruments in earnings as a component of revenue on the consolidated statements of operations.

 

 

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

 

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.

 

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

 

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts keeping one natural gas contract intact.

 

As of December 31, 2014, we had the following net open crude oil derivative positions:

 

										Weighted Average Contract Price
										Collars/Put Spreads
Remaining Contract Term		Type of  Contract		Index		Volumes (MBbls)				Sub Floor				Floor				Ceiling
January 2015 - December 2015		Three-Way Collars		Oil-Brent-IPE			3,650			$	71.00			$	91.00			$	113.75
January 2015 - December 2015		Collars		ARGUS-LLS			1,825								80.00				123.38
January 2015 - December 2015		Puts		NYMEX-WTI			405								86.11
January 2015 - December 2015		Put Spreads		ARGUS-LLS			2,555				70.00				80.00
January 2015 - December 2015		Collars		NYMEX-WTI			548								75.00				85.00
January 2015 - December 2015		Bought Put		NYMEX-WTI			1,593								89.15
January 2015 - December 2015		Sold Put		NYMEX-WTI			(1,593	)							(89.15	)
January 2016 - December 2016		Collars		NYMEX-WTI			732								70.00				90.55

     

As of December 31, 2014, we had the following net open natural gas derivative position:

 

Type of

Volumes

Swaps

Remaining Contract Term

Contract

Index

(MMBtu)

Fixed Price

January 2015 – December 2015

Swaps

NYMEX-HH

1,570

$

4.31

  

 

The fair values of derivative instruments in our consolidated balance sheets were as follows ( in thousands ):

 

		Asset Derivative Instruments												Liability Derivative Instruments
		December 31, 2014						June 30, 2014						December 31, 2014						June 30, 2014
		Balance  Sheet Location		Fair Value				Balance  Sheet Location		Fair Value				Balance  Sheet Location		Fair Value				Balance  Sheet Location		Fair Value
Derivative financial instruments		Current		$	287,172			Current		$	17,380			Current		$	137,146			Current		$	47,912
		Non- Current			10,670			Non- Current			9,595			Non- Current			2,293			Non- Current			10,866
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement					297,842						26,975						139,439						58,778
Derivative financial instruments		Current			(137,146	)		Current			(15,955	)		Current			(137,146	)		Current			(15,955	)
		Non- Current			(2,293	)		Non- Current			(6,560	)		Non- Current			(2,293	)		Non- Current			(6,560	)
Gross amounts offset in Balance Sheets					(139,439	)					(22,515	)					(139,439	)					(22,515	)
Net amounts presented in Balance Sheets		Current			150,026			Current			1,425			Current			—			Current			31,957
		Non- Current			8,377			Non- Current			3,035			Non- Current			—			Non- Current			4,306
				$	158,403					$	4,460					$	—					$	36,263

 

The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):

 

 

		Three Months Ended December 31,								Six Months Ended December 31,
Gain (loss) on derivative financial instruments		2014				2013				2014				2013
Cash Settlements, net of amortization of purchased put premiums		$	44,954			$	(1,801	)		$	43,220			$	(4,699	)
Proceeds from monetizations, net			25,873				—				29,236				—
Change in fair value			120,635				(19,150	)			175,731				(46,655	)
Total gain (loss) on derivative financial instruments		$	191,462			$	(20,951	)		$	248,187			$	(51,354	)

 

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At December 31, 2014, we had no deposits for collateral with our counterparties.

 

  

Note 10 – Income Taxes

 

We are a U.S. Delaware company and a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group. We operate through our various subsidiaries in the U. S.; accordingly, income taxes have been provided based upon the tax laws and rates of the U. S. as they apply to our current ownership structure. ASC Topic 740 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated financial reporting group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the year-to-date reporting period. We have recorded no income tax related intercompany balances with affiliates. However, in the current period, we have recorded a $329 million Impairment of Goodwill (addressed in Note 4 of the Notes to Consolidated Financial Statements).  In light of the form of the transaction related to the acquisition of EPL dated June 3, 2014, as stated in Note 3 of the Notes to Consolidated Financial Statements, “Acquisition of EPL Oil & Gas, Inc.”, the Goodwill recognized during fiscal year 2014 did not have tax basis, as such, the impairment is nondeductible for federal and state income tax purposes.

 

We have a remaining valuation allowance of $22.5 million related to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more likely-than-not basis, are realizable due to our current focus on offshore operations. While the U.S. consolidated group historically has paid no (significant) cash taxes, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We are a party to an intercompany agreement whereby we would be responsible for funding consolidated U.S. federal income tax payments. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

 

Note 11 – Supplemental Cash Flow Information

 

The following table presents our supplemental cash flow information (in thousands):

 

		Six Months Ended December 31,
		2014				2013
Cash paid for interest		$	111,208			$	60,917
Cash paid for income taxes			—				3,122

 

 The following table presents our non-cash investing and financing activities ( in thousands ):

 

		Six Months Ended December 31,
		2014				2013
Financing of insurance premiums		$	2,148			$	2,355
Derivative instruments premium financing			7,305				3,493
Additions to property and equipment by recognizing asset retirement obligations			21,912				28,050

 

Note 12 — Related Party Transactions

 

During the six months ended December 31, 2014 and 2013, we paid dividends of $0.8 million and $150.1 million, respectively, to our Parent.  During the six months ended December 31, 2014 and 2013, we returned net capital contributions of $19.9 million and $5.2 million, respectively, to our Parent.

 

 

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc. our indirect parent, bearing a simple interest of 2.78% per annum.  The note matures on December 16, 2021.  Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium.  Interest and principal are payable at maturity.  Interest on the note receivable amounted to approximately $482,000 and $482,000 for the three months ended December 31, 2014 and 2013, respectively.  Interest on the note receivable amounted to approximately $963,000 and $963,000 for the six months ended December 31, 2014 and 2013, respectively.  Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of December 31, 2014.

 

We reimbursed $3.6 million to our affiliate Energy XXI Insurance Limited for windstorm insurance coverage.  The coverage is for period from June 1, 2014 through June 1, 2015.

 

We have no employees; instead we receive management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company.  Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services.  Cost of these services for the three months and six months ended December 31, 2014 was approximately $27.4 million and $32.0 million, respectively, and cost of these services for the three months and six months ended December 31, 2013 was approximately $14.8 million, $36.4 million, respectively and is included in general and administrative expense.

 

Prior to the LLOG Exploration acquisition, we received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations.  In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced.  However, after the Eugene Island 330 and South Marsh Island 128 properties were purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced.  For the three and six months ended December 31, 2014, we received management fees of $0.5 million and $1.4 million, respectively.  For the three and six months ended December, 31, 2013, we received management fees of $1.1 million and $1.8 million, respectively.

 

On April 1, 2014, EXXI GOM sold its interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K and on June 3, 2014, it sold 100% of its interests in the South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Quarterly Report.

 

Note 13 — Commitments and Contingencies

 

Litigation.   We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.

 

Litigation Related to Merger

 

In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against the Company, EPL, its directors, Energy XXI, and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014.  The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

 

Plaintiffs alleged a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provided for the acquisition of EPL by Energy XXI. Plaintiffs alleged that (a) EPL’s directors allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs sought to have the merger agreement rescinded and also sought damages and attorneys’ fees.

 

On January 16, 2015, plaintiffs filed a voluntary notice of dismissal.  On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice.

 

 

BOEM and Other Bonding Related to Oil and Gas Property Abandonment

 

As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”), we maintain lease and/or area bonds issued to the BOEM that assures our commitment to comply with the terms and conditions of those leases.  We also maintain bonds issued to predecessor third party assignors of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities.  Notwithstanding these bonds currently in place, the BOEM has the authority to require OCS operators such as us to obtain and maintain supplemental bonds issued to the agency that serve to further assure compliance with lease obligations, most notably, decommissioning obligations including the permanent plugging of wells and removal of platforms, pipelines and related facilities.  Should the BOEM determine that supplemental bonding is required for decommissioning activities on one or more offshore leases, the agency generally will require the obligated lessee to obtain and maintain these supplemental bonds, which are issued to the BOEM.  Alternatively, the BOEM may waive this requirement to obtain and maintain supplemental bonds if the agency determines that the operator meets certain demonstrations of financial strength and reliability.  While we believe that the BOEM has waived the obligation to provide supplemental bonding based on such demonstrations, the BOEM retains the right to re-evaluate our decommissioning obligations or our market capitalization and asset impairments or otherwise amend the criteria that must be satisfied by an operator to qualify for waiver from supplemental bonding on the basis of financial strength and reliability and, as a result, determine that we no longer qualify for such waiver from the supplemental bonding requirements.  For example, in August 2014, the BOEM published an Advance Notice of Proposed Rulemaking, pursuant to which it seeks to bolster its current bonding requirements for offshore oil and gas operations.  The costs of satisfying supplemental bonding requirements could be substantial and there is no assurance that bonds or other surety could be obtained in all cases.  In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety.  Such a letter of credit would likely be issued under the Revolving Credit Facility, which would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations.  If we are unable to obtain any additional required bonds or assurances, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations.

 

Note 14 — Fair Value of Financial Instruments

 

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets.  Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

 

·

Level 1 – quoted prices in active markets for identical assets or liabilities.

 

·

Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

 

·

Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

 

For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.  For the 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

 

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 – Derivative Financial Instruments.

 

 

During the six months ended December 31, 2014, we did not have any transfers from or to Level 3. The following table sets forth our Level 2 financial assets and liabilities that are accounted for at fair value on a recurring basis (in thousands):

 

		Level 2
		As of December 31,				As of June 30,
		2014				2014
Assets:
Oil and natural gas derivatives		$	297,842			$	26,975
Liabilities:
Oil and natural gas derivatives		$	139,439			$	58,778

 

The following table sets forth the carrying values and estimated fair values of our long-term indebtedness which are classified as Level 2 financial instruments (in thousands):

 

		December 31, 2014								June 30, 2014
		Carrying Value				Estimated Fair Value				Carrying Value				Estimated  Fair Value
Revolving credit facility		$	941,309			$	941,309			$	689,000			$	689,000
8.25% Senior Notes due 2018			545,462				416,290				550,567				545,700
6.875% Senior Notes due 2024			650,000				359,130				650,000				663,000
7.5% Senior Notes due 2021			500,000				276,450				500,000				541,250
7.75% Senior Notes due 2019			250,000				152,750				250,000				269,480
9.25% Senior Notes due 2017			750,000				502,500				750,000				806,630
		$	3,636,771			$	2,648,429			$	3,389,567			$	3,515,060

 

Note 15 — Prepayments and Accrued Liabilities

 

Prepayments and accrued liabilities consist of the following (in thousands):

 

		December 31,				June 30,
		2014				2014
Prepaid expenses and other current assets
Advances to joint interest partners		$	8,477			$	10,336
Insurance			15,403				36,451
Inventory			7,030				7,020
Royalty deposit			10,263				12,262
Other			5,031				3,298
Total prepaid expenses and other current assets		$	46,204			$	69,367
Accrued liabilities
Advances from joint interest partners		$	2,961			$	2,667
Interest payable			36,764				26,490
Accrued hedge payable			—				7,874
Undistributed oil and gas proceeds			23,988				34,473
Severance taxes payable			1,510				8,014
Other			3,614				5,644
Total accrued liabilities		$	68,837			$	85,162

 

 

Note 16 — Subsequent Events

 

During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million; further, we repositioned our calendar 2015 hedging portfolio by entering into Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the current commodity prices.

 

Note 17 — Restatement of Previously Issued Consolidated Financial Statements

 

In connection with preparing our Consolidated Financial Statements for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging.  The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment.  Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings.  Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.

 

The effects of the restatement on our consolidated financial statements are summarized below:

 

·

Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue;

·

Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue;

·

Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and

·

Resulting adjustments required to deferred income taxes and income tax expense (benefit).

 

While these non-cash reclassifications impact revenues, net income (loss) in each period, as well as total stockholder’s equity, they have no material impact on cash flows. Details of the restatement applicable to these quarterly consolidated financial statements are as follows:

 

  

		As of December 31, 2014												As of June 30, 2014
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands)
Total Current Assets		$	358,416			$	-			$	358,416			$	316,200			$	-			$	316,200
Property and Equipment
Oil and natural gas properties, net			6,642,565				(93,035	)			6,549,530				6,524,602				(97,339	)			6,427,263
Other property and equipment			2,627				-				2,627				3,087				-				3,087
Total Property and Equipment, net			6,645,192				(93,035	)			6,552,157				6,527,689				(97,339	)			6,430,350
Total Other Assets			125,246				-				125,246				450,678				-				450,678
Total Assets		$	7,128,854			$	(93,035	)		$	7,035,819			$	7,294,567			$	(97,339	)		$	7,197,228
Total Current Liabilities		$	494,474			$	-			$	494,474			$	649,405			$	-			$	649,405
Deferred Income Taxes			701,436				(32,775	)			668,661				691,779				(34,092	)			657,687
Other Non-Current Liabilities			4,112,626				-				4,112,626				3,883,418				-				3,883,418
Total Liabilities			5,308,536				(32,775	)			5,275,761				5,224,602				(34,092	)			5,190,510
Stockholder’s Equity
Common stock			1				-				1				1				-				1
Additional paid-in capital			2,072,556				-				2,072,556				2,092,438				-				2,092,438
Accumulated deficit			(361,113	)			48,634				(312,499	)			(2,040	)			(83,681	)			(85,721	)
Accumulated other comprehensive loss, net of income taxes			108,894				(108,894	)			-				(20,434	)			20,434				-
Total Stockholder’s Equity			1,820,318				(60,260	)			1,760,058				2,069,965				(63,247	)			2,006,718
Total Liabilities and Stockholder’s Equity		$	7,128,854			$	(93,035	)		$	7,035,819			$	7,294,567			$	(97,339	)		$	7,197,228

 

 

		Three Months Ended  December 31, 2014												Three Months Ended  December 31, 2013
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands, except share information)
Revenues
Crude oil sales		$	324,655			$	(44,947	)		$	279,708			$	262,230			$	1,397			$	263,627
Natural gas sales			33,100				(1,299	)			31,801				34,586				(3,448	)			31,138
Gain (loss) on derivative financial instruments			-				191,462				191,462				-				(20,951	)			(20,951	)
Total Revenues			357,755				145,216				502,971				296,816				(23,002	)			273,814
Costs and Expenses
Depreciation, depletion and amortization			176,519				(2,178	)			174,341				102,511				(2,358	)			100,153
(Gain) loss on derivative financial instruments			(886	)			886				-				5,722				(5,722	)			-
All other costs and expenses			503,536				-				503,536				123,544				-				123,544
Total Costs and Expenses			679,169				(1,292	)			677,877				231,777				(8,080	)			223,697
Operating Income			(321,414	)			146,508				(174,906	)			65,039				(14,922	)			50,117
Other Income (Expense)
Other income, net			490				-				490				487				-				487
Interest expense			(60,637	)			-				(60,637	)			(35,837	)			-				(35,837	)
Total Other Expense, net			(60,147	)			-				(60,147	)			(35,350	)			-				(35,350	)
Income Before Income Taxes			(381,561	)			146,508				(235,053	)			29,689				(14,922	)			14,767
Income Tax Expense (Benefit)			(21,134	)			51,277				30,143				10,401				(5,223	)			5,178
Net Income			(360,427	)			95,231				(265,196	)			19,288				(9,699	)			9,589
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			195,263				(195,263	)			-				(8,858	)			8,858				-
Effective portion reclassified to earnings during the period			(51,225	)			51,225				-				(8,357	)			8,357				-
Total Other Comprehensive Loss			144,038				(144,038	)			-				(17,215	)			17,215				-
Income Tax Expense (Benefit)			50,413				(50,413	)			-				(6,025	)			6,025
Net Other Comprehensive Loss			93,625				(93,625	)			-				(11,190	)			11,190				-
Comprehensive Income		$	(266,802	)		$	1,606			$	(265,196	)		$	8,098			$	1,491			$	9,589

 

  

		Six Months Ended  December 31, 2014												Six Months Ended  December 31, 2013
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands, except share information)
Revenues
Crude oil sales		$	693,156			$	(43,293	)		$	649,863			$	551,459			$	3,134			$	554,593
Natural gas sales			67,830				(1,468	)			66,362				69,949				(6,227	)			63,722
Gain (loss) on derivative financial instruments			-				248,187				248,187				-				(51,354	)			(51,354	)
Total Revenues			760,986				203,426				964,412				621,408				(54,447	)			566,961
Costs and Expenses
Depreciation, depletion and amortization			337,047				(4,304	)			332,743				201,973				(4,915	)			197,058
(Gain) loss on derivative financial instruments			(4,169	)			4,169				-				7,163				(7,163	)			-
All other costs and expenses			686,214				-				686,214				244,705				-				244,705
Total Costs and Expenses			1,019,092				(135	)			1,018,957				453,841				(12,078	)			441,763
Operating Income			(258,106	)			203,561				(54,545	)			167,567				(42,369	)			125,198
Other Income (Expense)
Other income, net			954				-				954				970				-				970
Interest expense			(120,687	)			-				(120,687	)			(65,441	)			-				(65,441	)
Total Other Expense, net			(119,733	)			-				(119,733)				(64,471	)			-				(64,471	)
Income Before Income Taxes			(377,839	)			203,561				(174,278	)			103,096				(42,369	)			60,727
Income Tax Expense (Benefit)			(19,496	)			71,246				51,750				36,094				(14,829	)			21,265
Net Income			(358,343	)			132,315				(226,028	)			67,002				(27,540	)			39,462
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			252,179				(252,179	)			-				(31,515	)			31,515				-
Effective portion reclassified to earnings during the period			(53,214	)			53,214				-				(15,704	)			15,704				-
Total Other Comprehensive Loss			198,965				(198,965	)			-				(47,219	)			47,219				-
Income Tax Expense (Benefit)			69,637				(69,637	)			-				(16,527	)			16,527
Net Other Comprehensive Loss			129,328				(129,328	)			-				(30,692	)			30,692				-
Comprehensive Income		$	(229,015	)		$	2,987			$	(226,028	)		$	36,310			$	3,152			$	39,462

 

  

		Six Months Ended  December 31, 2014												Six Months Ended  December 31, 2013
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands)
Cash Flows From Operating Activities
Net income (loss)		$	(358,343	)		$	132,315			$	(226,028	)		$	67,002			$	(27,540	)		$	39,462
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			337,047				(4,304	)			332,743				201,973				(4,915	)			197,058
Goodwill impairment			329,293				-				329,293				-				-				-
Deferred income tax expense (benefit)			(19,496	)			71,246				51,750				36,094				(14,829	)			21,265
Change in fair value of derivative financial instruments			27,929				(203,660	)			(175,731	)			(364	)			47,019				46,655
Accretion of asset retirement obligations			25,617				-				25,617				14,751				-				14,751
Amortization and write-off of debt issuance costs and other			(683	)			-				(683	)			3,250				-				3,250
Changes in operating assets and liabilities
Accounts receivable			34,237				-				34,237				16,870				-				16,870
Prepaid expenses and other current assets			23,163				-				23,163				(5,111	)			-				(5,111	)
Settlement of asset retirement obligations			(53,960	)			-				(53,960	)			(34,038	)			-				(34,038	)
Accounts payable and accrued liabilities			(146,920	)			4,403				(142,517	)			(36,171	)			265				(35,906	)
Net Cash Provided by Operating Activities			197,884				-				197,884				264,256				-				264,256
Net Cash Used in Investing Activities			(435,620	)			-				(435,620	)			(398,541	)			-				(398,541	)
Net Cash Provided by Financing Activities			228,411				-				228,411				134,285				-				134,285
Net Increase (Decrease) in Cash and Cash Equivalents			(9,325	)			-				(9,325	)			-				-				-
Cash and Cash Equivalents, beginning of period			9,325								9,325				-								-
Cash and Cash Equivalents, end of period		$	-							$	-			$	-							$	-

 

 

Restated Unaudited Quarterly Financial Statements for the Three and Nine Months Ended March 31, 2015

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

(Unaudited)

		March 31,				June 30,
		2015				2014
		(Restated)				(Restated)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	553,081			$	9,325
Accounts receivable
Oil and natural gas sales			83,919				167,075
Joint interest billings			16,176				12,898
Other			23,236				4,099
Prepaid expenses and other current assets			36,855				69,367
Deferred income taxes			16,759				52,011
Derivative financial instruments			52,822				1,425
TOTAL CURRENT ASSETS			782,848				316,200
Property and Equipment
Oil and gas properties, net – full cost method of accounting, including $680.0 million and $1,165.7 million of unevaluated properties not being amortized at March 31, 2015 and June 30, 2014, respectively			5,521,558				6,427,263
Other property and equipment, net			2,403				3,087
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment			5,523,961				6,430,350
Other Assets
Goodwill			—				329,293
Note receivable from Energy XXI, Inc.			72,904				69,845
Derivative financial instruments			9,767				3,035
Restricted cash			6,024				6,350
Debt issuance costs, net of accumulated amortization			73,438				42,155
Total Other Assets			162,133				450,678
TOTAL ASSETS		$	6,468,942			$	7,197,228
LIABILITIES
CURRENT LIABILITIES
Accounts payable		$	190,384			$	416,576
Accrued liabilities			87,176				85,162
Notes payable			4,949				21,967
Asset retirement obligations			68,392				79,649
Derivative financial instruments			—				31,957
Current maturities of long-term debt			16,461				14,094
TOTAL CURRENT LIABILITIES			367,362				649,405
Long-term debt, less current maturities			4,239,812				3,396,473
Deferred income taxes			271,214				657,687
Asset retirement obligations			462,082				480,185
Derivative financial instruments			71				4,306
Other liabilities			5,332				2,454
TOTAL LIABILITIES			5,345,873				5,190,510
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares  authorized and 100,000 shares issued and outstanding			1				1
Additional paid-in capital			2,002,883				2,092,438
Accumulated deficit			(879,815	)			(85,721	)
TOTAL STOCKHOLDER’S EQUITY			1,123,069				2,006,718
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY		$	6,468,942			$	7,197,228

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands)

(Unaudited)

 

		Three Months Ended								Nine Months Ended
		March 31,								March 31,
		2015				2014				2015				2014
		(Restated)				(Restated)				(Restated)				(Restated)
Revenues
Oil sales		$	177,359			$	254,641			$	827,222			$	809,234
Natural gas sales			27,012				37,562				93,374				101,284
Gain (loss) on derivative financial instruments			16,963				(7,349	)			265,150				(58,703	)
Total Revenues			221,334				284,854				1,185,746				851,815
Costs and Expenses
Lease operating			107,711				83,624				369,662				263,176
Production taxes			1,537				1,090				6,893				3,677
Gathering and transportation			3,726				5,700				17,685				17,023
Depreciation, depletion and amortization			185,431				96,837				518,174				293,895
Accretion of asset retirement obligations			12,047				6,066				37,664				20,817
Impairment of oil and natural gas properties			700,194				—				700,194				—
Goodwill impairment			—				—				329,293				—
General and administrative expense			35,333				20,232				85,371				56,724
Total Costs and Expenses			1,045,979				213,549				2,064,936				655,312
Operating Income (Loss)			(824,645	)			71,305				(879,190	)			196,503
Other Income (Expense)
Other income, net			688				499				1,642				1,469
Interest expense			(78,852	)			(36,094	)			(199,539	)			(101,535	)
Total Other Expense			(78,164	)			(35,595	)			(197,897	)			(100,066	)
Income (Loss) Before Income Taxes			(902,809	)			35,710				(1,077,087	)			96,437
Income Tax Expense (Benefit)			(335,494	)			12,529				(283,744	)			33,794
Net Income (Loss)		$	(567,315	)		$	23,181			$	(793,343	)		$	62,643

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

 

		Nine Months Ended
		March 31,
		2015				2014
		(Restated)				(Restated)
Cash Flows from Operating Activities
Net income (loss)		$	(793,343	)		$	62,643
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense (benefit)			(284,035	)			33,794
Change in derivative financial instruments			(85,086	)			46,915
Accretion of asset retirement obligations			37,664				20,817
Depreciation, depletion and amortization			518,174				293,895
Impairment of oil and natural gas properties			700,194				—
Goodwill impairment			329,293				—
Amortization of debt issuance costs and other			8,485				4,698
Changes in operating assets and liabilities:
Accounts receivable			62,832				20,399
Prepaid expenses and other current assets			32,512				27,042
Settlement of asset retirement obligations			(77,177	)			(46,269	)
Accounts payable and other liabilities			(263,476	)			(9,967	)
Net Cash Provided by Operating Activities			186,037				453,967
Cash Flows from Investing Activities
Acquisitions			(301	)			(35,082	)
Capital expenditures			(505,825	)			(572,400	)
Insurance payments received			2,669				—
Transfer from (to) restricted cash			325				(325	)
Proceeds from the sale of properties			7,093				1,748
Other			—				570
Net Cash Used in Investing Activities			(496,039	)			(605,489	)
Cash Flows from Financing Activities
Proceeds from long-term debt			2,586,572				1,703,191
Payments on long-term debt			(1,729,033	)			(1,391,069	)
Advance to Energy XXI, Inc.			(3,059	)			(1,434	)
Contributions from parent			41,759				768
Dividends to parent			(750	)			(150,100	)
Debt issuance costs and other			(41,731	)			(9,834	)
Net Cash Provided by Financing Activities			853,758				151,522
Net Decrease in Cash and Cash Equivalents			543,756				—
Cash and Cash Equivalents, beginning of period			9,325				—
Cash and Cash Equivalents, end of period		$	553,081			$	—

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2015

(Unaudited)

 

Note 1 — Basis of Presentation

 

Nature of Operations. Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (our “Parent” or “EXXI USA”).  References in this report to “us,” “we,” “our,” or “the Company,” are to EGC and its wholly-owned subsidiaries.  Energy XXI Ltd (“Energy XXI”) indirectly owns 100% of our Parent.  We are headquartered in Houston, Texas and are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and in the Gulf of Mexico Shelf (“GoM Shelf”).

 

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of EGC and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

 

Interim Financial Statements. The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended June 30, 2015 included herein.

 

Use of Estimates.   The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value of estimates used in accounting for acquisitions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others.   Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates.  While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.

 

Note 2 – Recent Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

 

 

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued.  The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.

 

Note 3 – Acquisitions and Dispositions

 

Black Elk Interest

 

On December 20, 2013, we acquired certain offshore Louisiana interests in the West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for total cash consideration of $10.4 million.  This acquisition was effective as of October 1, 2013, and we are currently the operator of these properties.

 

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 ( in thousands ):

 

Oil and natural gas properties – evaluated		$	15,821
Oil and natural gas properties – unevaluated			6,586
Asset retirement obligations			(10,503	)
Net working capital *			(1,500	)
Cash paid		$	10,404

* Net working capital includes payables.

 

Walter Oil & Gas Corporation Oil and Gas Properties Interests

 

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for total cash consideration of approximately $22.8 million.  This acquisition was effective as of January 1, 2014 and we are currently the operator of these properties.

 

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014.  The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 ( in thousands ):

 

Oil and natural gas properties – evaluated		$	23,497
Asset retirement obligations			(705	)
Cash paid		$	22,792

 

We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates.  In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; (3) an inflation factor; and (4) a credit adjusted risk-free interest rate.  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 14 - Fair Value Measurements.

 

 

EPL Oil & Gas, Inc. (“EPL”)

 

We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method.  Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

 

In connection with the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election” and together with the Cash Election and the Stock Election, the “Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock.  Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share.  Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election.  In addition to the outstanding EPL shares, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration.  As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 per share in cash, without proration.    Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, 23.3 million shares of Energy XXI common stock were issued, and we paid approximately $1,012 million in cash.

  

The following table summarizes the preliminary purchase price allocation for the EPL Acquisition as of June 3, 2014 ( in thousands ):

 

		EPL Historical				Fair Value Adjustment				Total
						(Unaudited)
Current assets (excluding deferred income taxes)		$	301,592			$	1,274			$	302,866
Oil and natural gas properties a
Evaluated (Including net ARO assets)			1,919,699				112,624				2,032,323
Unevaluated			41,896				859,886				901,782
Other property and equipment			7,787				—				7,787
Other assets			16,227				(9,002	)			7,225
Current liabilities (excluding ARO)			(314,649	)			(2,058	)			(316,707	)
ARO (current and long-term)			(260,161	)			(13,211	)			(273,372	)
Debt (current and long-term)			(973,440	)			(52,967	)			(1,026,407	)
Deferred income taxes b			(118,359	)			(340,645	)			(459,004	)
Other long-term liabilities			(2,242	)			797				(1,445	)
Total fair value, excluding  goodwill			618,350				556,698				1,175,048
Goodwill c,d			—				329,293				329,293
Less cash acquired			—				—				206,075
Total purchase price		$	618,350			$	885,991			$	1,298,266

 

a.      EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

 

b.      Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit).

 

c.      See Note 4 - Goodwill for more information regarding goodwill impairment at December 31, 2014.

 

d.      On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million.  This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million.  Accordingly the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill.

 

 

In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates; and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.

 

The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.

 

The fair value estimates of the oil and natural gas properties and the asset retirement obligations were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value estimate of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.

 

The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase Energy XXI’s equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, which enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets.  During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.   See Note 4 - Goodwill for more information regarding the impairment of goodwill at December 31, 2014.

 

In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred.  For the quarter ended March 31, 2015, our Consolidated Statement of Operations includes EPL’s operating revenues of $87.3 million and net loss of $50.5 million.  For the nine months ended March 31, 2015, our Consolidated Statement of Operations includes EPL’s operating revenues of $418.0 million and net loss of $366.0 million.

 

The following supplemental unaudited pro forma financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on ours and EPL’s historical consolidated statements of income for the three and nine months ended March 31, 2014 (in thousands).

 

		Three Months Ended  March 31, 2014 (Restated)				Nine Months Ended  March 31, 2014 (Restated)
Revenues		$	445,415			$	1,364,845
Net income			25,262				26,136

 

 

The above supplemental unaudited pro forma financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments for the three and nine months ended March 31, 2014, were the following:

 

a.

Exclude $5.0 million and $22.0 million, respectively, of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with our full cost method of accounting.

 

b.

Increase DD&A expense by $13.5 million and $62.7 million, respectively, for the EPL properties to correspond with our full cost method of accounting.

 

c.

Increase interest expense by $12.8 million and $39.0 million, respectively, to reflect interest on the $650 million 6.875% unsecured senior notes due 2024 (the “6.875% Senior Notes”) and on additional borrowings under our revolving credit facility. Decrease interest expense $3.4 million and $10.0 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the  $510 million 8.25% senior notes due 2018 (the “8.25% Senior Notes”) assumed in the EPL acquisition.

 

Eugene Island 330 and South Marsh Island 128 Interest

 

On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of Energy XXI’s equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million.  Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014.  The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized.  The net reduction to the full cost pool related to this sale was $124.4 million.

 

Grand Isle Gathering System

 

On March 11, 2015, we distributed the Grand Isle gathering system (“Grand Isle Assets”) to our Parent pursuant to an assignment and bill of sale between certain of our subsidiaries and our Parent.  The Grand Isle Assets include a liquids gathering system consisting of a system of pipelines, storage tanks, processing facilities, salt water disposal facilities and related facilities and equipment.  This distribution resulted in a decrease in additional paid-in-capital with no gain or loss recognized.

 

The following table summarizes the assets and liabilities distributed (in thousands):

 

Oil and natural gas properties		$	201,424
Asset retirement obligations			(6,941	)
Deferred income taxes			(67,187	)
Net assets distributed		$	127,296

 

Note 4 – Goodwill

 

ASC 350, Intangibles—Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment.  Our annual goodwill impairment test is performed as of the last day of the fourth quarter each fiscal year.

 

Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.

 

At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves.  Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill.  As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.

 

 

In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using a weighted average cost of capital. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs.  The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.

 

Note 5 – Property and Equipment

 

Property and equipment consists of the following (in thousands):

 

		March 31,				June 30,
		2015				2014
		(Restated)				(Restated)
Oil and gas properties
Proved properties		$	9,044,937			$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment			4,203,428				2,985,790
Proved properties, net			4,841,509				5,261,562
Unevaluated properties			680,049				1,165,701
Oil and gas properties, net			5,521,558				6,427,263
Other property and equipment			3,226				3,173
Less: accumulated depreciation			823				86
Other property and equipment, net			2,403				3,087
Total property and equipment,  net of accumulated depreciation, depletion, amortization and impairment		$	5,523,961			$	6,430,350

 

At March 31, 2015, the Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL acquisition. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) amortization over a period of time of not more than four years.

  

At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties.  Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following:  1) the Lomond North project resulted in a successful production test with commercial production commencing in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the Blackbeard East project expired.  Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the nine months ended March 31, 2015.

 

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. At March 31, 2015, our ceiling test computation resulted in an impairment of our oil and natural gas properties of $700.2 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 2015 and 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

 

 

Note 6 – Long-Term Debt

 

Long-term debt consists of the following (in thousands):

 

		March 31,				June 30,
		2015				2014
Revolving Credit Facility		$	150,000			$	689,000
11.0% Senior Secured Second Lien Notes due 2020			1,450,000				—
9.25% Senior Notes due 2017			750,000				750,000
8.25% Senior Notes due 2018			510,000				510,000
7.75% Senior Notes due 2019			250,000				250,000
7.5% Senior Notes due 2021			500,000				500,000
6.875% Senior Notes due 2024			650,000				650,000
Debt premium, 8.25% Senior Notes due 2018 (1)			32,855				40,567
Original issue discount, 11.0% Senior Secured Second Lien Notes due 2020			(53,043	)			—
Derivative instruments premium financing			16,461				21,000
Total debt			4,256,273				3,410,567
Less current maturities			16,461				14,094
Total long-term debt		$	4,239,812			$	3,396,473

 

(1)

Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition.

 

Maturities of long-term debt as of March 31, 2015 are as follows (in thousands):

 

Twelve Months Ended March 31,
2016		$	16,461
2017			—
2018			750,000
2019			708,658
2020			1,700,000
Thereafter			1,150,000
			4,325,119
Less:  Net original issue discount & debt premium			(68,846	)
Total debt		$	4,256,273

 

Revolving Credit Facility

 

On March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”) in connection with the issuance of $1.45 billion of senior secured second lien notes as described below under “11.0% Senior Secured Second Lien Notes Due 2020.”  Under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement became effective:

 

·

reduction of the maximum facility amount to $500 million and establishment of the borrowing base at such $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement;

 

 

·

addition of provisions to permit EGC to make a loan to EPL in the amount of $325 million using proceeds from the incurrence of additional permitted second lien or third lien indebtedness of EGC and for EPL and its subsidiaries to secure such loan by providing liens on substantially all of their assets that are second in priority to the liens of the lenders under the First Lien Credit Agreement pursuant to the terms of an intercreditor agreement and restricting the transfer of EGC’s rights in respect of such loan or making any prepayment or otherwise making modifications of the terms of such arrangements;

 

·

change in the definition of the stated maturity date of the First Lien Credit Agreement so that it accelerates from April 9, 2018 (the scheduled date of maturity) to a date 210 days prior to the date of maturity of our outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of EPL’s outstanding 8.25% Senior Notes due February 2018 if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018;

 

·

elimination, addition, or modification of certain financial covenants;

 

·

setting the applicable commitment fee under the First Lien Credit Agreement at 0.50% and providing that outstanding amounts drawn under the First Lien Credit Agreement bear interest at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%;

 

·

increase of the threshold requirement for oil and gas properties required to be secured by mortgages to 90% of the value of our (other than EPL and its subsidiaries until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but allowing the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) to remain at 85%;

 

·

addition of certain further restrictions on the prepayment and repayment of our outstanding note indebtedness, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that we have net liquidity at the time thereof of at least $250 million;

 

·

modification to the restricted payment covenant to substantially limit our ability to make distributions and dividends to parent entities, provided that a distribution of the Grand Isle Assets and related equipment and other assets is permitted (see Note 12 - Related Party Transactions);

 

·

qualification on our ability to refinance outstanding indebtedness by requiring that we have pro forma net liquidity of $250 million at the time of such refinancing; and

 

·

modification of the asset disposition covenant to require lender consent for any such disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate; provided, however, that such provision is expressly deemed not to be applicable to certain sales relating to the Grand Isle Assets that are the subject of our current marketing efforts, as long as we meet certain obligations, such as, among others, maintaining the proceeds from such sales in accounts that are subject to the liens of the lenders.

 

During the quarter ended March 31, 2015, as a result of the reduction in the borrowing capacity under our Revolving Credit Facility pursuant to the Tenth Amendment, we wrote off $8.9 million of previously capitalized debt issue costs.

 

The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. We are subject to the following financial covenant on a consolidated basis:  a minimum current ratio of no less than 1.0 to 1.0.  In addition, EGC is subject to the following financial covenants on a stand-alone basis:  (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0.  In addition, EPL is subject to the following financial covenants on a stand-alone basis:  (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0.  If the EPL Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis:  (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the Revolving Credit Facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.

 

 

Under the First Lien Credit Agreement, as amended under the Tenth Amendment, our rights to make distributions to our shareholders (including ultimately to Energy XXI) are substantially reduced. Generally, under the Tenth Amendment, we are only permitted to make such distributions for income tax liabilities arising for such other entities that relate to the income attributable to us and our subsidiaries, general and administrative expenses not to exceed $2 million in any fiscal year and for payment of insurance premiums in regards to affiliated party insurance agreements.

 

As of March 31, 2015, we were in compliance with all covenants and had $150.0 million in borrowings and $226.0 million in letters of credit issued under the First Lien Credit Agreement.

 

11.0% Senior Secured Second Lien Notes Due 2020

 

On March 12, 2015, we issued $1.45 billion in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 (the “11.0% Notes”) pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, Energy XXI, our ultimate parent company, EXXI USA and certain of EGC’s wholly owned subsidiaries (together with Energy XXI and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the initial purchasers named therein (the “Initial Purchasers”).  We received net proceeds of approximately $1.35 billion in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The 11.0% Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.000%. The 11.0% Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. As such, the 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction.  The 11.0% Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15 th and September 15 th , beginning September 15, 2015.  We incurred underwriting and direct offering costs of $41.7 million which have been capitalized and are being amortized over the life of the 11.0% Notes.  The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the Initial Purchasers’ discount of $53.5 million as well as the direct offering costs.

 

The 11.0% Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”).  The 11.0% Notes are secured by second-priority liens on substantially all of EGC and our subsidiary guarantors’ assets and all of EXXI USA’s equity interests in us and its interests in certain assets related to the Grand Isle Assets, in each case to the extent such assets secure our Revolving Credit Facility. In the future, the 11.0% Notes may be guaranteed by certain of our material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.

 

The 11.0% Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of our future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture.  EXXI USA also guaranteed the notes on a non-recourse basis limited to the value of equity interests in us that it pledges to secure its guarantee and the Grand Isle Assets in which it grants a security interest in to secure its guarantee. Although the 11.0% Notes are guaranteed by Energy XXI and EXXI USA, Energy XXI and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.

 

 

On or after September 15, 2017, we will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, we may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We will be required to offer to purchase all outstanding 11.0% Notes if a ‘‘triggering event’’ occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a ‘‘triggering event’’ will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. If a change of control, as defined in the 2015 Indenture, occurs, each holder of the 11.0% Notes will have the right to require us to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

 

The 2015 Indenture restricts our ability and the ability of our restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of our assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.

 

8.25% Senior Notes Due 2018

 

On June 3, 2014, we assumed the 8.25% Senior Notes in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018.  On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL's obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

 

6.875% Senior Notes Due 2024

 

On May 27, 2014, we issued the 6.875% Senior Notes which consist of $650 million in aggregate principal amount due March 15, 2024.  On November 25, 2014, we filed a registration statement with the Securities and Exchange Commission (“SEC”) for an offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. On May 1, 2015, we filed Amendment No. 1 to the registration statement and the registration statement was declared effective by the SEC. The exchange offer commenced on May 4, 2015, and we currently expect to complete the exchange offer in June 2015.  EGC incurred underwriting and direct offering costs of approximately $11 million which were capitalized and are being amortized over the life of the 6.875% Senior Notes.

 

On or after March 15, 2019, we will have the right to redeem all or some of the 6.875% Senior Notes at redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the 6.875% Senior Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, we may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We are required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.

 

 

The indenture governing the 6.875% Senior Notes, among other things, limits our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

7.5% Senior Notes Due 2021

 

On September 26, 2013, we issued $500 million face value of 7.5% unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”).  In April 2014, we filed Amendment No. 1 to the registration statement with the SEC for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014.  We incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.

 

On or after December 15, 2016, we will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, we may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, we may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest.  We are required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.

 

The indenture governing the 7.5% Senior Notes limits, among other things, our ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

 

7.75% Senior Notes Due 2019

 

On February 25, 2011, we issued $250 million face value of 7.75% unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). We exchanged the full $250 million aggregate principal amount of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

 

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.

 

9.25% Senior Notes Due 2017

 

On December 17, 2010, we issued $750 million face value of 9.25% unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal amount of the 9.25% Old Senior Notes for $749 million aggregate principal amount of the 9.25% Senior Notes registered under the Securities Act on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

 

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. We incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.

 

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.

 

 

Derivative Instruments Premium Financing

 

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of March 31, 2015 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $16.5 million and $21.0 million, respectively.

 

Interest Expense

 

For the three and nine months ended March 31, 2015 and 2014, interest expense consisted of the following (in thousands):

 

		Three Months Ended								Nine Months Ended
		March 31,								March 31,
		2015				2014				2015				2014
Revolving Credit Facility		$	7,526			$	2,782			$	21,901			$	10,327
11.0% Notes due 2020			8,740				—				8,740				—
9.25% Senior Notes due 2017			17,343				17,343				52,031				52,031
8.25% Senior Notes due 2018			10,518				—				31,556				—
7.75% Senior Notes due 2019			4,843				4,843				14,531				14,531
7.50% Senior Notes due 2021			9,375				9,375				28,125				19,167
6.875% Senior Notes due 2024			11,172				—				33,516				—
Amortization of debt issue cost – Revolving Credit Facility			9,845				571				11,902				2,232
Accretion of original debt issue discount, 11.0% Notes due 2020			418				—				418				—
Amortization of debt issue cost – 11.0% Notes due 2020			327				—				327				—
Amortization of debt issue cost – 9.25% Senior Notes due 2017			552				551				1,655				1,655
Amortization of fair value premium – 8.25% Senior Notes due 2018			(2,608	)			—				(7,712	)			—
Amortization of debt issue cost – 7.75% Senior Notes due 2019			97				97				291				291
Amortization of debt issue cost – 7.50% Senior Notes due 2021			263				260				788				520
Amortization of debt issue cost – 6.875% Senior Notes due 2024			282				—				845				—
Derivative instruments financing and other			159				272				625				781
		$	78,852			$	36,094			$	199,539			$	101,535

 

Note 7 – Notes Payable

 

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015.  The balance outstanding as of March 31, 2015 was $4.0 million.

 

On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015.  The balance outstanding as of March 31, 2015 was $0.9 million.

 

 

Note 8 – Asset Retirement Obligations

 

The following table describes the changes to our asset retirement obligations (in thousands):

 

Balance at June 30, 2014		$	559,834
Liabilities incurred and true-up to liabilities settled			20,411
Liabilities settled			(77,177	)
Liabilities sold and transferred			(10,258	)
Accretion expense			37,664
Total balance at March 31, 2015			530,474
Less current portion			68,392
Long-term balance at March 31, 2015		$	462,082

 

Note 9 – Derivative Financial Instruments

 

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from the change in fair value from hedging transactions are recorded as gain (loss) on derivative financial instruments in earnings as a component of revenue on the consolidated statements of operations.

 

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

 

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.

 

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

 

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts keeping one natural gas contract intact.

 

As of March 31, 2015, we had the following net open crude oil derivative positions:

 

										Weighted Average Contract Price
		Type of				Volumes				Collars/Put
Remaining Contract Term		Contract		Index		(MBbls)				Sub Floor				Floor				Ceiling
April 2015 - December 2015		Three-Way Collars		ARGUS-LLS			5,500			$	32.50			$	45.00			$	75.00
April 2015 - December 2015		Collars		ARGUS-LLS			1,375								80.00				123.38
April 2015 - December 2015		Collars		NYMEX-WTI			413								75.00				85.00
April 2015 - December 2015		Bought Put		NYMEX-WTI			1,053								90.00
April 2015 - December 2015		Sold Put		NYMEX-WTI			(1,053	)							90.00
January 2016 - December 2016		Collars		NYMEX-WTI			5,124								51.43				74.70

 

 

As of March 31, 2015, we had the following net open natural gas derivative position:

 

Type of

Volumes

Swaps

Remaining Contract Term

Contract

Index

(MMBtu)

Fixed Price

April 2015 - December 2015

Swaps

NYMEX-HH

1,183

$

4.31

 

The fair values of derivative instruments in our consolidated balance sheets were as follows ( in thousands ):

 

		Asset Derivative Instruments												Liability Derivative Instruments
		March 31, 2015						June 30, 2014						March 31, 2015						June 30, 2014
		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
Derivative financial instruments		Current		$	104,660			Current		$	17,380			Current		$	51,838			Current		$	47,912
		Non- Current			20,860			Non- Current			9,595			Non- Current			11,164			Non- Current			10,866
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement					125,520						26,975						63,002						58,778
Derivative financial instruments		Current			(51,838	)		Current			(15,955	)		Current			(51,838	)		Current			(15,955	)
		Non- Current			(11,093	)		Non- Current			(6,560	)		Non- Current			(11,093	)		Non- Current			(6,560	)
Gross amounts offset in Balance Sheets					(62,931	)					(22,515	)					(62,931	)					(22,515	)
Net amounts presented in Balance Sheets		Current			52,822			Current			1,425			Current			—			Current			31,957
		Non- Current			9,767			Non- Current			3,035			Non- Current			71			Non- Current			4,306
				$	62,589					$	4,460					$	71					$	36,263

 

The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):

 

		Three Months Ended March 31,								Nine Months Ended March 31,
Gain (loss) on derivative financial instruments		2015				2014				2015				2014
Cash Settlements, net of amortization of purchased put premiums		$	34,491			$	(7,089	)		$	77,710			$	(11,788	)
Proceeds from monetizations, net			73,117				—				102,354				—
Change in fair value			(90,645	)			(260	)			85,086				(46,915	)
Total gain (loss) on derivative financial instruments		$	16,963			$	(7,349	)		$	265,150			$	(58,703	)

 

  

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At March 31, 2015, we had no deposits for collateral with our counterparties.

 

Note 10 – Income Taxes

 

We are a U.S. Delaware company and a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group. We operate through our various subsidiaries in the U.S.; accordingly, income taxes have been provided based upon the tax laws and rates of the U.S. as they apply to our current ownership structure. ASC Topic 740 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated financial reporting group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the year-to-date reporting period. We have recorded no income tax related intercompany balances with affiliates. However, during the second quarter of fiscal year 2015, we recorded a goodwill impairment charge of $329 million (see Note 4 - Goodwill).  In light of the form of the transaction related to the acquisition of EPL on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition during fiscal year 2014 did not have tax basis.  Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes.

 

We have a remaining valuation allowance of $23.8 million related to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more likely-than-not basis, are realizable due to our current focus on offshore operations. However, the transfer of the Grand Isle Assets generated current year Louisiana-only taxable income this period; thus we have released $3.0 million of previously recorded Louisiana valuation allowance as a discrete item this quarter. While the U.S. consolidated group historically has paid no (significant) cash taxes, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We are a party to an intercompany agreement whereby we would be responsible for funding consolidated U.S. federal income tax payments. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

 

Note 11 – Supplemental Cash Flow Information

 

The following table presents our supplemental cash flow information ( in thousands ):

 

		Nine Months Ended March 31,
		2015				2014
Cash paid for interest		$	164,383			$	63,854
Cash paid for income taxes			—				3,362

 

The following table presents our non-cash investing and financing activities ( in thousands ):

 

		Nine Months Ended March 31,
		2015				2014
Financing of insurance premiums		$	931			$	2,355
Derivative instruments premium financing			12,025				3,493
Additions to property and equipment by recognizing asset retirement obligations			20,411				38,513
Net distribution of Grand Isle Assets to parent (1)			127,296				—

(1) See Note 3- Acquisitions and Dispositions

 

 

Note 12 — Related Party Transactions

 

On March 11, 2015, we distributed the Grand Isle Assets to our Parent pursuant to an assignment and bill of sale between certain of our subsidiaries and our Parent.   The Grand Isle Assets include a liquids gathering system consisting of a system of pipelines, storage tanks, processing facilities, salt water disposal facilities and related facilities and equipment.   This distribution resulted in a decrease in additional paid-in-capital of $127.3 million, reflecting the net book value of the assets distributed, net of related deferred tax liabilities.

 

Also on March 11, 2015, we entered into an agreement with our Parent providing for the transportation of certain of our oil production on the Grand Isle gathering system.  For the quarter ended March 31, 2015, we incurred charges totaling $2.0 million related to transportation services under this agreement.

 

During the nine months ended March 31, 2015 and 2014, we paid dividends of $0.8 million and $150.1 million, respectively, to our Parent.  During the nine months ended March 31, 2015 and 2014, our Parent contributed approximately $41.8 million and $0.8 million, respectively, to us.

 

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc. our indirect parent, bearing a simple interest of 2.78% per annum.  The note matures on December 16, 2021.  Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium.  Interest and principal are payable at maturity.  Interest on the note receivable amounted to approximately $0.5 million for the three months ended March 31, 2015 and 2014.  Interest on the note receivable amounted to approximately $1.4 million for the nine months ended March 31, 2015 and 2014.  Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of March 31, 2015.

 

During the nine months ended March 31, 2015, we reimbursed $3.0 million to our affiliate Energy XXI Insurance Limited for windstorm insurance coverage.  The coverage is for period from June 1, 2014 through June 1, 2015.

 

We have no employees; instead we receive management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company.  Services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services.  Cost of these services for the three months and nine months ended March 31, 2015 was approximately $34.8 million and $66.9 million, respectively, and the cost of these services for the three months and nine months ended March 31, 2014 was approximately $19.7 million and $56.1 million, respectively.  These costs are included in general and administrative expense.

 

Prior to M21K acquiring the interests in certain oil and natural gas fields owned by LLOG Exploration Offshore, L.L.C. ( the “LLOG Exploration acquisition”), we received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations.  In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced.  However, after the Eugene Island 330 and South Marsh Island 128 properties were purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced.  For the three and nine months ended March 31, 2015, we received management fees of $0.7 million and $2.1 million, respectively.  For the three and nine months ended March 31, 2014, we received management fees of $1.0 million and $2.8 million, respectively.

 

On April 1, 2014, EXXI GOM sold its interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K and on June 3, 2014, it sold 100% of its interests in the South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Quarterly Report.

 

Note 13 — Commitments and Contingencies

 

Litigation.   We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.

 

Litigation Related to Merger

 

In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against the Company, EPL, its directors, Energy XXI, and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014.  The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

 

 

Plaintiffs alleged a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provided for the acquisition of EPL by Energy XXI. Plaintiffs alleged that (a) EPL’s directors allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs sought to have the merger agreement rescinded and also sought damages and attorneys’ fees.

 

On January 16, 2015, plaintiffs filed a voluntary notice of dismissal.  On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice.

 

Bureau of Ocean Energy Management ("BOEM") and Other Bonding Related to Oil and Gas Property Abandonment

 

As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”), we maintain approximately $7.5 million in lease and/or area bonds issued to the BOEM that assures our commitment to comply with the terms and conditions of those leases.  We also maintain approximately $162.5 million in bonds issued to predecessor third party assignors of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements that require supplemental bonding. The BOEM has indicated the amount of such required supplemental bonding totals approximately $1.0 billion, which amount is currently being negotiated by us.  We are currently evaluating the impact of the BOEM letters on our future consolidated financial position, results of operations and cash flow.  We intend to continue to work with the BOEM staff to resolve this matter, and we have already undertaken a number of initiatives to mitigate our potential liability resulting from the waiver disqualification and to limit the amount of required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date as well as counting our existing bonds with third parties and certain letters of credit against the BOEM bonding request. The costs of satisfying these supplemental bonding requirements could be substantial and there is no assurance that bonds or other surety could be obtained in all cases.  In addition, we may be required to provide letters of credit or other collateral to support the issuance of any required bonds or other surety.  Such letters of credit would likely be issued under our Revolving Credit Facility, which would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations.  If we are unable to obtain the additional required bonds or assurances requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations.

 

Note 14 — Fair Value of Financial Instruments

 

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets.  Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

 

·

Level 1 – quoted prices in active markets for identical assets or liabilities.

·

Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

·

Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

 

 

For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.  For the 11.0% Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, and 6.875% Senior Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

 

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 – Derivative Financial Instruments.

 

During the nine months ended March 31, 2015, we did not have any transfers from or to Level 3. The following table sets forth our Level 2 financial assets and liabilities that are accounted for at fair value on a recurring basis (in thousands): 

 

		Level 2
		As of March 31,				As of June 30,
		2015				2014
Assets:
Oil and natural gas derivatives		$	125,520			$	26,975
Liabilities:
Oil and natural gas derivatives		$	63,002			$	58,778

 

The following table sets forth the carrying values and estimated fair values of our long-term indebtedness which are classified as Level 2 financial instruments ( in thousands ):

 

		March 31, 2015								June 30, 2014
		Carrying Value				Estimated Fair Value				Carrying Value				Estimated Fair Value
Revolving credit facility		$	150,000			$	150,000			$	689,000			$	689,000
11.0% Senior Notes due 2020			1,396,957				1,384,750				—				—
8.25% Senior Notes due 2018			542,855				379,761				550,567				545,700
6.875% Senior Notes due 2024			650,000				234,000				650,000				663,000
7.5% Senior Notes due 2021			500,000				192,415				500,000				541,250
7.75% Senior Notes due 2019			250,000				108,233				250,000				269,480
9.25% Senior Notes due 2017			750,000				518,295				750,000				806,630
		$	4,239,812			$	2,967,454			$	3,389,567			$	3,515,060

 

The 11.0% Notes, the 8.25% Senior Notes, the 6.875%  Senior Notes, and the 7.5% Senior Notes  each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings.  Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at March 31, 2015 are not material.

 

 

Note 15 — Prepayments and Accrued Liabilities

 

Prepayments and accrued liabilities consist of the following ( in thousands ):

 

		March 31,				June 30,
		2015				2014
Prepaid expenses and other current assets
Advances to joint interest partners		$	8,219			$	10,336
Insurance			6,461				36,451
Inventory			7,849				7,020
Royalty deposit			10,490				12,262
Other			3,836				3,298
Total prepaid expenses and other current assets		$	36,855			$	69,367
Accrued liabilities
Advances from joint interest partners		$	3,087			$	2,667
Interest payable			52,713				26,490
Accrued hedge payable			1,145				7,874
Undistributed oil and gas proceeds			20,145				34,473
Severance taxes payable			892				8,014
Other			9,194				5,644
Total accrued liabilities		$	87,176			$	85,162

 

Note 16 — Restatement of Previously Issued Consolidated Financial Statements

 

In connection with preparing our Consolidated Financial Statements for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging.  The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment.  Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings.  Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.

 

The effects of the restatement on our consolidated financial statements are summarized below:

 

·

Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue;

·

Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue;

·

Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and

·

Resulting adjustments required to deferred income taxes and income tax expense (benefit).

 

 

While these non-cash reclassifications impact revenues, net income (loss) in each period, as well as total stockholder’s equity, they have no material impact on cash flows. Details of the restatement applicable to these quarterly consolidated financial statements are as follows:

 

		As of March 31, 2015												As of June 30, 2014
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands)
Total Current Assets		$	782,848			$	-			$	782,848			$	316,200			$	-			$	316,200
Property and Equipment
Oil and natural gas properties, net			5,442,041				79,517				5,521,558				6,524,602				(97,339	)			6,427,263
Other property and equipment			2,403				-				2,403				3,087				-				3,087
Total Property and Equipment, net			5,444,444				79,517				5,523,961				6,527,689				(97,339	)			6,430,350
Total Other Assets			162,133				-				162,133				450,678				-				450,678
Total Assets		$	6,389,425			$	79,517			$	6,468,942			$	7,294,567			$	(97,339	)		$	7,197,228
Total Current Liabilities		$	367,362			$	-			$	367,362			$	649,405			$	-			$	649,405
Deferred Income Taxes			243,525				27,689				271,214				691,779				(34,092	)			657,687
Other Non-Current Liabilities			4,707,297				-				4,707,297				3,883,418				-				3,883,418
Total Liabilities			5,318,184				27,689				5,345,873				5,224,602				(34,092	)			5,190,510
Stockholder’s Equity
Common stock			1				-				1				1				-				1
Additional paid-in capital			2,002,883				-				2,002,883				2,092,438				-				2,092,438
Accumulated deficit			(1,016,764)				136,949				(879,815	)			(2,040	)			(83,681	)			(85,721	)
Accumulated other comprehensive loss, net of income taxes			85,121				(85,121	)			-				(20,434	)			20,434				-
Total Stockholder’s Equity			1,071,241				51,828				1,123,069				2,069,965				(63,247	)			2,006,718
Total Liabilities and Stockholder’s Equity		$	6,389,425			$	79,517			$	6,468,942			$	7,294,567			$	(97,339	)		$	7,197,228

 

 

 

		Three Months Ended  March 31, 2015												Three Months Ended  March 31, 2014
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands, except share information)
Revenues
Crude oil sales		$	232,274			$	(54,915	)		$	177,359			$	249,955			$	4,686			$	254,641
Natural gas sales			27,672				(660	)			27,012				35,228				2,334				37,562
Gain (loss) on derivative financial instruments			-				16,963				16,963				-				(7,349	)			(7,349	)
Total Revenues			259,946				(38,612	)			221,334				285,183				(329	)			284,854
Costs and Expenses
Depreciation, depletion and amortization			187,658				(2,227	)			185,431				99,028				(2,191	)			96,837
Impairment of oil and natural gas properties			870,519				(170,325	)			700,194				-				-				-
(Gain) loss on derivative financial instruments			1,932				(1,932	)			-				(205	)			205				-
All other costs and expenses			160,354				-				160,354				116,712				-				116,712
Total Costs and Expenses			1,220,463				(174,484	)			1,045,979				215,535				(1,986	)			213,549
Operating Income			(960,517	)			135,872				(824,645	)			69,648				1,657				71,305
Other Income (Expense)
Other income, net			688				-				688				499				-				499
Interest expense			(78,852	)			-				(78,852	)			(36,094	)			-				(36,094	)
Total Other Expense, net			(78,164	)			-				(78,164	)			(35,595	)			-				(35,595	)
Income Before Income Taxes			(1,038,681	)			135,872				(902,809	)			34,053				1,671				35,710
Income Tax Expense (Benefit)			(383,050	)			47,556				(335,494	)			11,949				580				12,529
Net Income			(655,631	)			88,316				(567,315	)			22,104				1,077				23,181
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			24,399				(24,399	)			-				(4,221	)			4,221				-
Effective portion reclassified to earnings during the period			(60,973	)			60,973				-				3,621				(3,621	)			-
Total Other Comprehensive Loss			(36,574	)			36,574				-				(600	)			600				-
Income Tax Expense (Benefit)			(12,801	)			12,801				-				(210	)			210
Net Other Comprehensive Loss			(23,773	)			23,773				-				(390	)			390				-
Comprehensive Income		$	(679,404	)		$	112,089			$	(567,315	)		$	21,714			$	1,467			$	23,181

 

 

		Nine Months Ended  March 31, 2015												Nine Months Ended  March 31, 2014
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands, except share information)
Revenues
Crude oil sales		$	925,430			$	(98,208	)		$	827,222			$	801,414			$	7,820			$	809,234
Natural gas sales			95,502				(2,128	)			93,374				105,177				(3,893	)			101,284
Gain (loss) on derivative financial instruments			-				265,150				265,150				-				(58,703	)			(58,703	)
Total Revenues			1,020,932				164,814				1,185,746				906,591				(54,776	)			851,815
Costs and Expenses
Depreciation, depletion and amortization			524,705				(6,531	)			518,174				301,001				(7,106	)			293,895
Impairment of oil and natural gas properties			870,519				(170,325)				700,194				-				-				-
(Gain) loss on derivative financial instruments			(2,237	)			(2,237	)			-				6,958				(6,958	)			-
All other costs and expenses			846,568				-				846,568				361,417				-				361,417
Total Costs and Expenses			2,239,555				(174,619	)			2,064,936				669,376				(14,064	)			655,312
Operating Income			(1,218,623	)			339,433				(879,190	)			237,215				(40,712	)			196,503
Other Income (Expense)
Other income, net			1,642				-				1,642				1,469				-				1,469
Interest expense			(199,539	)			-				(199,539	)			(101,535	)			-				(101,535	)
Total Other Expense, net			(197,897	)			-				(197,897	)			(100,066	)			-				(100,066	)
Income Before Income Taxes			(1,416,520	)			339,433				(1,077,087	)			137,149				(40,712	)			96,437
Income Tax Expense (Benefit)			(402,546	)			118,802				(283,744	)			48,043				(14,249	)			33,794
Net Income			(1,013,974	)			220,631				(793,343	)			89,106				(26,463	)			62,643
Other Comprehensive Loss
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			276,577				(276,577	)			-				(35,736	)			35,736				-
Effective portion reclassified to earnings during the period			(114,186	)			114,186				-				(12,083	)			12,083				-
Total Other Comprehensive Loss			162,391				(162,391	)			-				(47,819	)			47,819				-
Income Tax Expense (Benefit)			56,836				(56,836	)			-				(16,737	)			16,737
Net Other Comprehensive Loss			105,555				(105,555	)			-				(31,082	)			31,082				-
Comprehensive Income		$	(908,419	)		$	115,076			$	(793,343	)		$	58,024			$	4,619			$	62,643

 

 

		Nine Months Ended  March 31, 2015												Nine Months Ended  March 31, 2014
		As Reported				Adjustment				Restated				As Reported				Adjustment				Restated
		(In thousands)
Cash Flows From Operating Activities
Net income (loss)		$	(1,013,974	)		$	220,631			$	(793,343	)		$	89,106			$	(26,463	)		$	62,643
Adjustments to reconcile net income (loss) to net cash  provided by operating activities:
Depreciation, depletion and amortization			524,705				(6,531	)			518,174				301,001				(7,106	)			293,895
Impairment of oil and natural gas properties			870,519				(170,325	)			700,194				-								-
Goodwill impairment			329,293				-				329,293				-				-				-
Deferred income tax expense (benefit)			(402,837	)			118,802				(284,035	)			48,043				(14,249	)			33,794
Change in fair value of derivative financial instruments			103,102				(188,188	)			(85,086	)			(549	)			47,464				46,915
Accretion of asset retirement obligations			37,664				-				37,664				20,817				-				20,817
Amortization and write-off of debt issuance costs and other			8,485				-				8,485				4,698				-				4,698
Changes in operating assets and liabilities
Accounts receivable			62,832				-				62,832				20,399				-				20,399
Prepaid expenses and other current assets			32,512				-				32,512				27,042				-				27,042
Settlement of asset retirement obligations			(77,177	)			-				(77,177	)			(46,269	)			-				(46,269	)
Accounts payable and accrued liabilities			(289,087	)			25,611				(263,476	)			(10,321	)			354				(9,967	)
Net Cash Provided by Operating Activities			186,037				-				186,037				453,967				-				453,967
Net Cash Used in Investing Activities			(469,039	)			-				(469,039	)			(605,489	)			-				(605,489	)
Net Cash Provided by Financing Activities			853,758				-				853,758				151,522				-				151,522
Net Increase (Decrease) in Cash and Cash Equivalents			543,756				-				543,756				-				-				-
Cash and Cash Equivalents, beginning of period			9,325								9,325				-								-
Cash and Cash Equivalents, end of period		$	553,081							$	553,081			$	-							$	-