ENERGY XXI GULF COAST, INC.

 

CONSOLIDATED FINANCIAL STATEMENTS

 

MARCH 31, 2014

 

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2014

 

 

 

 

C O N T E N T S

 

 

 

	Page
Consolidated Balance Sheets	3
Consolidated Statements of Income	4
Consolidated Statements of Comprehensive Income	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

 

		March 31,				June 30,
		2014				2013
		(Unaudited)
ASSETS
CURRENT ASSETS
Restricted cash		$	325			$	—
Receivables:
Oil and natural gas sales			129,604				132,521
Joint interest billings			5,210				9,505
Insurance and other			7,268				5,367
Prepaid expenses and other current assets			20,822				47,864
Derivative financial instruments			3,393				38,389
TOTAL CURRENT ASSETS			166,622				233,646
Oil and gas properties-net – full cost method of accounting, including    $263.2 million and $422.6 million of unevaluated properties not being amortized    at March 31, 2014 and June 30, 2013, respectively			3,625,788				3,289,505
Other Assets
Note receivable from Energy XXI USA, Inc.			69,369				67,935
Derivative financial instruments			966				21,926
Debt issuance costs, net of accumulated amortization			29,928				24,791
TOTAL ASSETS		$	3,892,673			$	3,637,803
LIABILITIES
CURRENT LIABILITIES
Accounts payable		$	214,169			$	219,822
Accrued liabilities			71,549				58,334
Notes payable			3,037				22,349
Asset retirement obligations			30,457				29,500
Derivative financial instruments			2,593				40
Current maturities of long-term debt			10,019				18,838
TOTAL CURRENT LIABILITIES			331,824				348,883
Long-term debt, less current maturities			1,669,631				1,344,843
Deferred taxes			185,112				153,805
Asset retirement obligations			264,029				258,318
Derivative financial instruments			2				—
Other liabilities			1,429				—
TOTAL LIABILITIES			2,452,027				2,105,849
COMMITMENTS AND CONTINGENCIES (NOTE 11)
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			1,427,117				1,426,349
Retained earnings			18,310				79,304
Accumulated other comprehensive income (loss), net of
income taxes			(4,782	)			26,300
TOTAL STOCKHOLDER’S EQUITY			1,440,646				1,531,954
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY		$	3,892,673			$	3,637,803

 

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

(Unaudited)

 

		Three Months Ended								Nine Months Ended
		March 31,								March 31,
		2014				2013				2014				2013
Revenues
Oil sales		$	249,955			$	274,364			$	801,414			$	807,518
Natural gas sales			35,228				29,410				105,177				87,002
Total Revenues			285,183				303,774				906,591				894,520
Costs and Expenses
Lease operating			83,624				86,305				263,176				254,708
Production taxes			1,090				1,352				3,677				3,765
Gathering and transportation			5,700				4,411				17,023				18,500
Depreciation, depletion and amortization			99,028				87,759				301,001				276,655
Accretion of asset retirement obligations			6,066				7,649				20,817				23,057
General and administrative			20,232				15,072				56,724				55,006
Loss (gain) on derivative financial instruments			(205	)			(622	)			6,958				5,898
Total Costs and Expenses			215,535				201,926				669,376				637,589
Operating Income			69,648				101,848				237,215				256,931
Other Income (Expense)
Other income			499				443				1,469				1,371
Interest expense			(36,094	)			(27,596	)			(101,535	)			(81,122	)
Total Other Expense			(35,595	)			(27,153	)			(100,066	)			(79,751	)
Income Before Income Taxes			34,053				74,695				137,149				177,180
Income Tax Expense			11,949				26,252				48,043				62,296
Net Income		$	22,104			$	48,443			$	89,106			$	114,884

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Thousands)

(Unaudited)

 

 

 

		Three Months Ended March 31,								Nine Months Ended March 31,
		2014				2013				2014				2013
Net Income		$	22,104			$	48,443			$	89,106			$	114,884
Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion			(4,221	)			(2,017	)			(35,736	)			(38,356	)
Effective portion reclassified to earnings during the period			3,621				(7,165	)			(12,083	)			(28,502	)
Total Other Comprehensive Loss			(600	)			(9,182	)			(47,819	)			(66,858	)
Income Tax Benefit			210				3,214				16,737				23,400
Net Other Comprehensive Loss			(390	)			(5,968	)			(31,082	)			(43,458	)
Comprehensive Income		$	21,714			$	42,475			$	58,024			$	71,426

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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,
		2014				2013
Cash Flows from Operating Activities
Net income		$	89,106			$	114,884
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization			301,001				276,655
Deferred income tax expense			48,043				62,296
Change in derivative financial instruments
Proceeds from sale of derivative instruments			—				735
Other – net			(549	)			(19,326	)
Accretion of asset retirement obligations			20,817				23,057
Amortization of debt issuance costs			4,698				5,677
Changes in operating assets and liabilities:
Accounts receivables			20,399				(9,475	)
Prepaid expenses and other current assets			27,042				9,803
Asset retirement obligations			(46,269	)			(29,570	)
Accounts payable and other liabilities			(10,321	)			47,154
Net Cash Provided by Operating Activities			453,967				481,890
Cash Flows from Investing Activities
Acquisitions			(35,082	)			(153,722	)
Capital expenditures			(572,400	)			(554,408	)
Transfer to restricted cash			(325	)			—
Proceeds from the sale of properties			1,748				—
Other			570				(6	)
Net Cash Used in Investing Activities			(605,489	)			(708,136	)
Cash Flows from Financing Activities
Dividends to parent			(150,100	)			—
Proceeds from long-term debt			1,703,191				1,136,949
Payments on long-term debt			(1,391,069	)			(928,713	)
Advances to Energy XXI USA, Inc.			(1,434	)			(1,359	)
Contributions from (returns to) parent			768				(25,875	)
Debt issuance costs and other			(9,834	)			(150	)
Net Cash Provided by Financing Activities			151,522				180,852
Net Decrease in Cash and Cash Equivalents			—				(45,394	)
Cash and Cash Equivalents, beginning of period			—				45,394
Cash and Cash Equivalents, end of period		$	—			$	—

 

 

See accompanying Notes to Consolidated Financial Statements

 

 

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2014

(UNAUDITED)

 

Note 1 — Basis of Presentation

 

Nature of Operations. Energy XXI Gulf Coast, Inc. (“Energy XXI”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”).  Energy XXI (Bermuda) Limited (“Bermuda”), indirectly owns 100% of Parent. Energy XXI (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. Our consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income, stockholder’s equity or cash flows.

 

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, 2013.

 

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 December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We adopted ASU 2011-11 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

 

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income included in equity in one place. Total changes in accumulated other comprehensive income by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We adopted ASU 2013-02 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

 

 

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 are currently evaluating the provisions of ASU 2013-11 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

 

ExxonMobil oil and gas properties interests acquisition

 

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $32.8 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VR 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. The objective targets at Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned.  Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently analyzing the Pendragon and Merlin wells’ data along with reprocessing the 3D seismic information to determine the future drilling activities on the Vermilion Block. 

 

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

 

Oil and natural gas properties – evaluated		$	10,447
Oil and natural gas properties – unevaluated			27,721
Asset retirement obligations			(5,351	)
Cash paid		$	32,817

 

 

Dynamic Offshore oil and gas properties interests acquisition

 

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VR 164 for approximately $7.2 million.

 

Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income. The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

 

Oil and natural gas properties – evaluated		$	1,753
Oil and natural gas properties – unevaluated			6,571
Asset retirement obligations			(1,091	)
Cash paid		$	7,233

 

 

McMoRan oil and gas properties interests acquisition

 

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $79.3 million. This acquisition was effective as of January 1, 2013. We are the operator of these properties.

 

Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income. The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

 

 

Oil and natural gas properties – evaluated		$	62,499
Oil and natural gas properties – unevaluated			17,184
Asset retirement obligations			(382	)
Cash paid		$	79,301

 

 

RoDa oil and gas properties interests acquisition

 

On March 14, 2013, we acquired 100% of the interests (“RoDa Interests”) held by RoDa Drilling LP (“RoDa”) in the Bayou Carlin field for $32.7 million. This acquisition was effective as of January 1, 2013.

 

Revenues and expenses related to the RoDa Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the RoDa Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

 

Oil and natural gas properties – evaluated		$	32,777
Asset retirement obligations			(115	)
Cash paid		$	32,662

 

 

Tammany oil and gas properties interests acquisition

 

On June 28, 2013, we closed on the acquisition of certain offshore Louisiana interests in the West Delta field (“West Delta Interests”) from Tammany Energy Ventures, LLC (“Tammany”) for a total cash consideration of $8.3 million. This acquisition was effective as of June 1, 2013. We are the operator of these properties.

 

Revenues and expenses related to the West Delta Interests are included in our consolidated statements of income from July 1, 2013. The acquisition of West Delta Interests was accounted for under the purchase 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 June 28, 2013 (in thousands):

 

Oil and natural gas properties – evaluated		$	8,626
Asset retirement obligations			(338	)
Cash paid		$	8,288

 

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 (“Black Elk”) for a total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013. We will be the operator of these properties.

 

 

Revenues and expenses related to the West Delta 30 Interests will be included in our consolidated statements of income from December 20, 2013. The acquisition of West Delta 30 Interests was accounted for under purchase 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 (“Walter”) for a total cash consideration of approximately $22.8 million. This acquisition is effective January 1, 2014 and we will be the operator of these properties.

 

Revenues and expenses related to the South Timbalier 54 Interests will be included in our consolidated statements of income from March 7, 2014. The acquisition of South Timbalier 54 Interests was accounted for under purchase 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 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 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 Gulf of Mexico 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 March 31, 2014. We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program. 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 angle azimuth (“WAZ”) seismic data analysis in December 2014. As of March 31, 2014, our share of costs related to these wells was approximately $28.1 million.

 

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

 

On March 12, 2014, we and Bermuda signed a definitive merger agreement with EPL, pursuant to which Bermuda will acquire all of EPL’s outstanding shares for total considerations of $2,300 million, including the assumption of debt. The consideration to be received by EPL stockholders is valued at $39.00 per EPL share based on Bermuda’s closing price of $23.37 per share as of March 11, 2014. The aggregate consideration to EPL shareholders will be paid 65% in cash and 35% in Bermuda common shares and is expected to consist of approximately $1,000 million in cash and approximately 23.4 million common shares of Bermuda. Upon closing, Bermuda shareholders are expected to own approximately 75% of the combined company and EPL shareholders are expected to own the remaining 25%.

 

Bermuda, in addition to utilizing cash on hand to finance the pending acquisition, in conjunction with signing the definitive merger agreement with EPL, we obtained commitments to increase our revolving credit facility from $1,087.5 million to $1,675 million. Bermuda obtained a $400 million unsecured bridge loan to augment our existing revolving credit facility if EPL’s 8.25% Senior Notes are repurchased following the put option exercised by EPL’s 8.25% Senior Note holders as a result of the change in control.

 

On April 7, 2014, Bermuda received early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, in connection with its pending acquisition of EPL. The early termination of the waiting period under the Hart-Scott-Rodino Act satisfies one of the conditions for consummation of the transaction. Bermuda also commenced consent solicitation with respect to proposed amendments to the indenture governing the 8.25% Senior Notes due 2018 of EPL upon the terms and subject to the conditions set forth in the Consent Solicitation Statement.

 

Since the pending acquisition is subject to approval by the shareholders of both Bermuda and EPL as well as certain regulatory approvals, on April 14, 2014, Bermuda and EPL established a record date of April 21, 2014 and a meeting date of May 30, 2014 for the special meetings of both of its shareholders to approve the merger and certain other items related to the merger.

 

On April 17, 2014, Bermuda received consents from a majority of EPL’s 8.25% Senior Note holders waiving their rights to exercise their put options over EPL’s 8.25% Senior Notes in return for a consent fee of $2.50 per $1,000 principal amount of 8.25% Senior Notes. The consent fee will be paid to consenting 8.25% Senior Note holders upon the closing of the EPL acquisition.

.

Sale of Oil and Gas properties interests

 

On April 1, 2014, we closed on the sale of our 100% interests in Eugene Island 330 and South Marsh Island 128 fields (“Sold Properties”) to M21K, LLC, which is a wholly owned subsidiary of Bermuda’s equity method investee, Energy XXI M21K, LLC, for cash consideration of approximately $122.9 million. Revenues and expenses related to the Sold Properties have been included in our results of operations through March 31, 2014. The proceeds will be recorded as a reduction to our oil and gas properties with no gain or loss being recognized. We are presently evaluating the net reduction to the full cost pool related to this sale, which is subject to customary closing adjustments.

 

Note 4 – Property and Equipment

 

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

 

		March 31,				June 30,
		2014				2013
Oil and gas properties
Proved properties		$	6,132,328			$	5,335,737
Less: accumulated depreciation, depletion, amortization and impairment			2,769,784				2,468,783
Proved properties - net			3,362,544				2,866,954
Unevaluated properties			263,244				422,551
Total oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment		$	3,625,788			$	3,289,505

 

 

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 these unproved properties are transferred to evaluated properties upon the earlier of (i) when a determination is made whether there are any proved reserves related to the properties, or (ii) amortized over a period of time of not more than four years.

 

 

Exploratory wells in progress include $172.6 million in costs related to our participation with Freeport-McMoRan Oil & Gas LLC (Freeport McMoRan) who operates several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) 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 March 31, 2014, the costs associated with our major projects and their status was as follows (in millions):

 

Project Name		Cost				Status
Davy Jones Facilities		$	21.9			Facilities cost in Davy Jones field for well operations.
Davy Jones Offset Appraisal Well			58.9			Completion operations have commenced, flow testing expected in the first half of calendar year 2014.
Blackbeard East			50.6			Plans to begin development of the shallow zones in late calendar year 2014.
Lomond North			41.2			Completion operations in progress to test lower Wilcox and Cretaceous objectives
Total		$	172.6

 

 

Note 5 – Long-Term Debt

 

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

		March 31,				June 30,
		2014				2013
Revolving credit facility		$	167,000			$	339,000
9.25% Senior Notes due 2017			750,000				750,000
7.75% Senior Notes due 2019			250,000				250,000
7.50% Senior Notes due 2021			500,000				—
Derivative instruments premium financing			12,650				24,681
Total debt			1,679,650				1,363,671
Less current maturities			10,019				18,838
Total long-term debt		$	1,669,631			$	1,344,843

 

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

 

Twelve Months Ended March 31,
2015		$	10,019
2016			2,631
2017			—
2018			750,000
2019			167,000
Thereafter			750,000
Total		$	1,679,650

 

Revolving Credit Facility

 

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) in May 2011. This facility, as amended, has lender commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined 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, as amended, we are permitted to make dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, we and our subsidiaries have liquidity, in the form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement.  Further, the amendment limits the total aggregate distributions made by us to a maximum of $70 million plus 50% of our cumulative consolidated net income between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to us.

 

On April 7, 2014, we entered into the Seventh Amendment (the “Seventh Amendment”) to the First Lien Credit Agreement. Under the Seventh Amendment, our borrowing base was established at $1,200 million (an increase from $1,087.5 million) until the next redetermination of such borrowing base pursuant to the terms of the First Lien Credit Agreement. The Seventh Amendment incorporates concepts relating to our 7.50% senior unsecured notes due 2021 so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing therein for our 9.25% senior unsecured notes due 2017 and 7.75% senior unsecured notes due 2019, and permits us to incur up to $1,000 million of additional similar unsecured indebtedness. Any such issue of additional unsecured debt is subject to a requirement that we maintain revolver availability (in addition to what may otherwise be required under the First Lien Credit Agreement) in an amount equal to 25% of such additional unsecured debt issued, until such requirement is waived by the lenders under the First Lien Credit Agreement.

 

On April 16, 2014, we had a borrowing base redetermination meeting with the lenders to increase the borrowing base under our revolving credit facility from $1,200 million to $1,675 million. We are presently awaiting response from the lenders.

 

The First Lien Credit Agreement, as amended, requires us to maintain certain financial covenants. Specifically, we may not permit the following under the First Lien Credit Agreement: (a) our total leverage ratio to be more than 3.5 to 1.0, (b) our interest coverage ratio to be less than 3.0 to 1.0, and (c) our current ratio (in each case as defined in our First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. 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, the 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 March 31, 2014, we were in compliance with all covenants under the First Lien Credit Agreement.

 

High Yield 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 (“9.25% Old Senior Notes”). We 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 of 1933, as amended (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 have been capitalized and will be 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.

 

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2014 was $819.4 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 ( “7.75% Old Senior Notes”). We 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 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.

 

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2014 was $275.6 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

 

7.50% Senior Notes Due 2021

 

On September 26, 2013, we issued $500 million face value of 7.50%, unsecured senior notes due December 15, 2021 at par (“7.50% Senior Notes”). Presently, the 7.50% Senior Notes are not registered under the Securities Act, however EGC and its guarantors will agree, pursuant to a registration rights agreement with the initial purchasers of the 7.50% 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 7.50% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 270 days after the issue date of the 7.50% 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 the exchange process is presently in progress. We incurred underwriting and direct offering costs of $7.5 million which have been capitalized and will be amortized over the life of the 7.50% Senior Notes.

 

On or after December 15, 2016, we will have the right to redeem all or some of the 7.50% 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 7.50% 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 7.50% 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 7.50% 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 7.50% Senior Notes.

 

The indenture governing the 7.50% Senior Notes will, among other things, limit 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 7.50% Senior Notes outstanding as of March 31, 2014 was $525.3 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 Us

 

We are the issuer of each of the 9.25% Senior Notes, 7.75% Senior Notes and 7.50% Senior Notes, which are fully and unconditionally guaranteed by Bermuda and each of our existing and future material domestic subsidiaries. Bermuda and our subsidiaries, other than us, have no 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 March 31, 2014 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $12.7 million and $24.7 million, respectively.

 

 

Interest Expense

 

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

 

		Three Months Ended March 31,								Nine Months Ended March 31,
		2014				2013				2014				2013
Revolving credit facility		$	2,782			$	3,330			$	10,327			$	8,185
9.25% Senior Notes due 2017			17,343				17,343				52,031				52,031
7.75% Senior Notes due 2019			4,843				4,843				14,531				14,531
7.50% Senior Notes due 2021			9,375				—				19,167				—
Amortization of debt issue cost - Revolving credit facility			571				1,231				2,232				3,732
Amortization of debt issue cost – 9.25% Senior Notes due 2017			551				552				1,655				1,655
Amortization of debt issue cost – 7.75% Senior Notes due 2019			97				97				291				291
Amortization of debt issue cost – 7.5% Senior Notes due 2021			260				—				520				—
Derivative instruments financing and other			272				200				781				697
		$	36,094			$	27,596			$	101,535			$	81,122

 

Note 6 – Notes Payable

 

In May 2012, 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 $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

 

In July 2012, we entered into an additional note to finance a portion of our insurance premiums. The note was for a total face amount of $3.6 million and bore interest at an annual rate of 1.667%. The note matured and was repaid on May 1, 2013.

 

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 in September 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 bears interest at an annual rate of 1.623%. The note matures on April 26, 2014.  The balance outstanding as of March 31, 2014 was $2.2 million.

 

In July 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our Weather Based Insurance Linked Securities premiums. The note was for a total face amount of $2.9 million and bears interest at an annual rate of 1.823%. The note matures on June 1, 2014.  The balance outstanding as of March 31, 2014 was $0.8 million.

 

Note 7 – Asset Retirement Obligations

 

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

 

 

Balance at June 30, 2013		$	287,818
Liabilities acquired			11,289
Liabilities incurred			38,513
Liabilities settled			(46,269	)
Revisions			(17,682	)
Accretion expense			20,817
Total balance at March 31, 2014			294,486
Less current portion			30,457
Long-term balance at March 31, 2014		$	264,029

 

 

 

Note 8 – Derivative Financial Instruments

 

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions for our derivative transactions to reduce the concentration of exposure to any individual counterparty and to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. We designate a majority of our derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

 

When we discontinue cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

 

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. 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”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. During the quarter ended September 30, 2011, we began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and 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.

 

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended March 31, 2013, and received $181.3 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of December 31, 2013, all of the monetized amounts remaining in OCI were recognized in income.

 

During the quarter ended March 31, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and were recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of December 31, 2013, all of the amounts remaining in deferred hedge revenue were recognized in income.

  

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

 

														Weighted Average Contract Price
														Collars/Put Spreads
Period				Type of Contract		Index				Volumes  (MBbls)				Sub Floor				Floor				Ceiling
	April 2014 - December 2014			Three-Way Collars			Oil-Brent-IPE				1,683			$	68.18			$	88.18			$	130.23
	April 2014 - December 2014			Collars			Oil-Brent-IPE				550				—				90.00				108.38
	April 2014 - December 2014			Put Spreads			Oil-Brent-IPE				105				66.43				86.43				—
	April 2014 - December 2014			Three-Way Collars			NYMEX-WTI				2,450				70.00				90.00				137.15
	April 2014 - December 2014			Put Spreads			NYMEX-WTI				300				70.00				90.00				—
	January 2015 - December 2015			Three-Way Collars			Oil-Brent-IPE				3,650				71.00				91.00				113.75

 

  

As of March 31, 2014, we had the following open natural gas derivative positions:

 

Weighted Average Contract Price

Collars

Period

Type of Contract

Index

Volumes (MMBtu)

Sub Floor

Floor

Ceiling

April 2014 – December 2014

Three-Way Collars

NYMEX-HH

13,750

$

3.35

$

4.00

$

4.61

 

 

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

  

		Asset Derivative Instruments												Liability Derivative Instruments
		March 31, 2014						June 30, 2013						March 31, 2014						June 30, 2013
		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments		Current		$	15,357			Current		$	52,216			Current		$	14,576			Current		$	14,609
		Non-Current			10,400			Non-Current			42,263			Non-Current			9,436			Non-Current			20,337
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current			23			Current			1,976			Current			4			Current			1,234
		Non-Current			—			Non-Current			—			Non-Current			—			Non-Current			—
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement					25,780						96,455						24,016						36,180
Derivative financial instruments		Current			(11,987	)		Current			(15,803	)		Current			(11,987	)		Current			(15,803	)
		Non-Current			(9,434	)		Non-Current			(20,337	)		Non-Current			(9,434	)		Non-Current			(20,337	)
Gross amounts offset in Balance Sheet					(21,421	)					(36,140	)					(21,421	)					(36,140	)
Net amounts presented in Balance Sheet		Current			3,393			Current			38,389						2,593						40
		Non-Current			966			Non-Current			21,926						2						—
				$	4,359					$	60,315					$	2,595					$	40

 

 

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

 

		Three Months Ended March 31,								Nine Months Ended March 31,
		2014				2013				2014				2013
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales		$	4,686			$	(1,084	)		$	7,819			$	(10,455	)
Natural gas sales			2,334				(2,340	)			(3,893	)			(12,879	)
Total cash settlements			7,020				(3,424	)			3,926				(23,334	)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments     Ineffective portion of commodity derivative instruments			(268	)			(816	)			7,407				3,800
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments     Realized mark to market (gain) loss			70				(41	)			(1,150	)			1,932
Unrealized mark to market (gain) loss			(7	)			235				701				166
Total (gain) loss on derivative financial instruments			(205	)			(622	)			6,958				5,898
Total (gain) loss		$	6,815			$	(4,046	)		$	10,884			$	(17,436	)

 

 

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

 

Location of (Gain) Loss		Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)				Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)				Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended March 31, 2014
Commodity Derivative Instruments		$	390
Revenues						$	2,354
Gain on derivative financial instruments										$	(268	)
Total (gain) loss		$	390			$	2,354			$	(268	)
Three Months Ended March 31, 2013
Commodity Derivative Instruments		$	5,968
Revenues						$	(4,657	)
Gain on derivative financial instruments										$	(816	)
Total (gain) loss		$	5,968			$	(4,657	)		$	(816	)
Nine Months Ended March 31, 2014
Commodity Derivative Instruments		$	31,082
Revenues						$	(7,854	)
Loss on derivative financial instruments										$	7,407
Total (gain) loss		$	31,082			$	(7,854	)		$	7,407
Nine Months Ended March 31, 2013
Commodity Derivative Instruments		$	43,458
Revenues						$	(18,526	)
Loss on derivative financial instruments										$	3,800
Total (gain) loss		$	43,458			$	(18,526	)		$	3,800

 

 

  

Reconciliation of the components of AOCI representing all the reclassifications out of AOCI to income for the periods presented is as follow (in thousands):

 

		Before Tax				After Tax				Location Where Consolidated Net Income is Presented
Three months ended March 31, 2014
Unrealized loss on derivatives at beginning of period		$	6,758			$	4,392
Unrealized change in fair value			3,953				2,570
Ineffective portion reclassified to earnings during the period			268				174			Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period			(3,622	)			(2,354	)		Revenues
Unrealized loss on derivatives at end of period		$	7,357			$	4,782

 

Three months ended March 31, 2013
Unrealized gain on derivatives at beginning of period		$	(30,943	)		$	(20,113	)
Unrealized change in fair value			1,201				780
Ineffective portion reclassified to earnings during the period			816				530			Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period			7,165				4,658			Revenues
Unrealized gain on derivatives at end of period		$	(21,761	)		$	(14,145	)

 

		Before Tax				After Tax				Location Where Consolidated Net Income is Presented
Nine months ended March 31, 2014
Unrealized gain on derivatives at beginning of period		$	(40,461	)		$	(26,300	)
Unrealized change in fair value			28,328				18,414
Ineffective portion reclassified to earnings during the period			7,407				4,815			Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period			12,083				7,853			Revenues
Unrealized loss on derivatives at end of period		$	7,357			$	4,782

 

Nine months ended March 31, 2013
Unrealized gain on derivatives at beginning of period		$	(88,621	)		$	(57,603	)
Unrealized change in fair value			34,558				22,461
Ineffective portion reclassified to earnings during the period			3,800				2,470			Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period			28,502				18,527			Revenues
Unrealized gain on derivatives at end of period		$	(21,761	)		$	(14,145	)

 

 

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a loss of $6.3 million ($4.1 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

 

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 March 31, 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.  Bermuda, 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 consolidated group has not made a cash income tax payment in this quarter, 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 US 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 March 31,								Nine Months Ended March 31,
		2014				2013				2014				2013
Cash paid for interest		$	2,937			$	3,329			$	63,854			$	50,768
Cash paid for income taxes			239				4,056				3,362				7,017

 

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

 

		Three Months Ended March 31,								Nine Months Ended March 31,
		2014				2013				2014				2013
Financing of insurance premiums		$	—			$	(1,266	)		$	2,355			$	(21,131	)
Derivative instruments premium financing			—				12,780				3,493				14,001
Additions to property and equipment by    recognizing asset retirement obligations			10,463				1,816				38,513				11,605

 

 

Note 11 - Related Party Transactions

 

During the nine months ended March 31, 2014 we paid dividends of $150.1 million to our Parent and our Parent contributed $768,000 to us. During nine months ended March 31, 2013, we returned capital of $25.9 million 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 $0.5 million and $1.4 million for the three months and nine months ended March 31, 2014, respectively. Interest on the note receivable amounted to approximately $0.5 million and $1.4 million for the three months and nine months ended March 31, 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 March 31, 2014.

 

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 nine months ended March 31, 2014 was approximately $19.7 million and $56.1 million, respectively, and cost of these services for the three months and nine months ended March 31, 2013 was approximately $14.5 million, $53.8 million, respectively and is included in general and administrative expense.

 

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 the Merger. On March 19, 2014, an alleged EPL stockholder (the “Lopez plaintiff”) filed a class action lawsuit on behalf of EPL stockholders against EPL, its directors, Bermuda, the Company (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). This lawsuit is styled Antonio Lopez v. EPL Oil & Gas, Inc., et al., C.A. No. 9460, in the Court of Chancery of the State of Delaware (the “Lopez lawsuit”). On April 14, 2014, another alleged EPL stockholder (the “Lewandoski plaintiff”) filed a class action lawsuit on behalf of EPL stockholders against defendants. This lawsuit is styled David Lewandoski v. EPL Oil & Gas, Inc., et al., C.A. No. 9533, in the Court of Chancery of the State of Delaware (the “Lewandoski lawsuit”).  On April 23, 2014, another alleged EPL stockholder (the “Feinstein plaintiff”) filed a class action lawsuit on behalf of EPL stockholders against defendants. This lawsuit is styled Roberta Feinstein v. EPL Oil & Gas, Inc., et al., C.A. No. 9570, in the Court of Chancery of the State of Delaware (the “Feinstein lawsuit” and, together with the Lopez lawsuit and Lewandoski lawsuit, the “lawsuits”).

 

Plaintiffs allege a variety of causes of action challenging the Agreement and Plan of Merger between Bermuda, OpCo, Merger Sub, and EPL (the “merger agreement”), which provides for the acquisition of EPL by Bermuda.  Plaintiffs allege that (a) EPL’s directors have allegedly breached fiduciary duties in connection with the merger and (b) Bermuda, 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 provides 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 will allegedly dissuade other potential acquirers from making competing offers for shares of EPL common stock; (iii) certain of EPL’s officers and directors are allegedly receiving benefits—including (A) an offer for one of EPL’s directors to join Bermuda’s board of directors and (B) the triggering of change-in-control provisions in notes held by EPL’s executive officers—that are not equally shared by EPL’s stockholders; (iv) Bermuda 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 Bermuda obtained, non-public information that allegedly allowed Bermuda to acquire EPL for inadequate consideration.  The Lopez plaintiff also alleges that the Registration Statement filed on Form S-4 by EPL and Bermuda 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 Bermuda, and (v) the analysis of EPL’s financial advisor.  The Feinstein plaintiff also alleges that (a) certain of EPL’s officers and directors are allegedly receiving additional benefits—including (i) future coverage under the surviving company’s directors’ and officers’ liability insurance, (ii) bonuses, and (iii) consulting roles—that are not equally shared by EPL’s stockholders; and (b) the Joint Proxy Statement filed by EPL and Bermuda on April 21, 2014 omits information concerning, among other things, (i) certain management projection metrics, (ii) the analysis of Bermuda’s and EPL’s financial advisors; (iii) the events leading up to the merger, (iv) EPL’s efforts to attract offers from other potential acquirors; and (v) the aforementioned voting agreements.

 

Based on these allegations, plaintiffs seek to enjoin the defendants from proceeding with or consummating the merger. To the extent that the merger is consummated before injunctive relief is granted, plaintiffs seek to have the merger agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

 

The Lopez plaintiff has served defendants (other than Bermuda) and is seeking expedited proceedings.  Defendants date to answer, move to dismiss, or otherwise respond to the Lopez lawsuit is May 5, 2014, though this date may be changed if the Court grants expedited proceedings. The Lewandoski plaintiff and Feinstein plaintiff have not yet served the defendants. Neither Bermuda nor EPL can predict the outcome of the lawsuits or any others that might be filed subsequent to the date of the filing of this quarterly report; nor can either Bermuda or EPL predict the amount of time and expense that will be required to resolve the lawsuits. The defendants intend to vigorously defend the lawsuits.

 

Letters of Credit and Performance Bonds.   We had $225.3 million in letters of credit and $44.5 million of performance bonds outstanding as of March 31, 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 March 31, 2014, we have entered into the following drilling rig commitments:

 

1)  October 10, 2013 to April 10, 2014 at $49,000 per day

2)  October 31, 2013 to June 30, 2014 at $125,000 per day

3)  September 1, 2013 to August 31, 2014 at $140,000 per day

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

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

 

At March 31, 2014, future minimum commitments under these contracts totaled $62.4 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.

 

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model is used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

 

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.

 

 

During the nine months ended March 31, 2014, 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 March 31,				As of   June 30,
		2014				2013
Assets:
Oil and natural gas derivatives		$	25,780			$	96,455
Liabilities:
Oil and natural gas derivatives		$	24,016			$	36,180

 

 

 

Note 14 — Prepayments and Accrued Liabilities

 

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

 

		March 31,				June 30,
		2014				2013
Prepaid expenses and other current assets
Advances to joint interest partners		$	10,756			$	13,936
Insurance			4,066				28,417
Inventory			3,253				4,094
Royalty deposit			2,333				1,210
Other			414				207
Total prepaid expenses and other current assets		$	20,822			$	47,864
Accrued liabilities
Advances from joint interest partners		$	430			$	1,348
Interest payable			38,771				5,733
Accrued hedge payable			944				2,214
Undistributed oil and gas proceeds			29,977				47,766
Other			1,427				1,273
Total accrued liabilities		$	71,549			$	58,334