HOUSTON, Aug. 09, 2018 (GLOBE NEWSWIRE) -- Energy XXI Gulf Coast, Inc. (“EGC” or the “Company”) (NASDAQ: EGC) today reported financial and operational results for the second quarter of 2018. 

Second Quarter 2018 Highlights and Recent Key Items:

• Announced definitive agreement to be acquired by affiliates of Cox Oil LLC (“Cox”) for approximately $322 million, or $9.10 per fully diluted share
• Produced an average of approximately 25,300 barrels of oil equivalent (“BOE”) per day, of which 83% was oil
• Incurred a net loss of $34.0 million, or $1.02 per share, which included a $26.0 million loss on derivative financial instruments
• Generated Adjusted EBITDA of $27.8 million
• Initiated production from two successful development wells drilled in 2018 following the completion of the replaced pipeline at West Delta. The West Delta 74 C-41 ST01 Cato development well was brought online with initial production averaging approximately 600 BOE per day. The West Delta 73 C-27 ST02 McCloud development well is currently being brought online.
• Currently drilling the South Timbalier 54 G-25 ST01 Koala well

For the second quarter of 2018, EGC reported a net loss of $34.0 million, or $1.02 loss per diluted share, which included a $26.0 million loss on derivative financial instruments. In the first quarter of 2018, the Company reported a net loss of $33.1 million, or $0.99 loss per diluted share, which included a $12.8 million loss on financial derivative instruments.

Adjusted EBITDA totaled $27.8 million for the second quarter 2018, compared to $13.6 million in the first quarter of 2018.

Adjusted EBITDA is a Non-GAAP financial measure and is described and reconciled to net loss in the attached table under “Reconciliation of Non-GAAP Measures.”

Douglas E. Brooks, President and Chief Executive Officer commented, “Strategically, we continue to advance the previously-announced merger with affiliates of Cox Oil LLC and we are pleased with the progress. Details on the transaction are in our proxy statement, which has been finalized and was distributed earlier this week. In the meantime, our focus is to continue to deliver results and maintain the value of our assets for all EGC stockholders. During the first half of the year we worked diligently to address the Company’s financial and operational challenges, while maintaining our commitment to safety.”

Production and Pricing
In the second quarter of 2018, the Company produced and sold approximately 25,300 net BOE per day, within its previously-provided guidance range of 24,500 to 26,000 BOE per day.  EGC continued to benefit from the impact of higher realized oil prices (before the effect of derivatives) that were about 2% higher than average WTI prices during the quarter due to the positive differentials that EGC receives on its oil sales.

		Quarter Ended
		June 30,			March 31,			June 30,
		2018			2018			2017
		(In thousands, except per unit amounts)
Sales volumes per day
Oil (MBbls)			21.1			21.1			26.8
Natural gas liquids (MBbls)			0.3			0.4			1.0
Natural gas (MMcf)			23.6			30.6			48.9
Total (MBOE)			25.3			26.6			35.9
Percent of sales volumes from oil			83%			79%			75%
Average sales price before hedging impact
Oil per Bbl		$	69.54		$	65.09		$	48.57
Natural gas liquid per Bbl			34.98			37.01			27.37
Natural gas per Mcf			2.92			3.04			3.09

When compared with the first quarter of 2018, second quarter higher realized prices were offset by higher production downtime primarily related to continued production equipment maintenance, pipeline shut-ins, third-party operator downtime, EGC facility-related unscheduled downtime, and natural decline. In late July, EGC restored production through the previously-shut in pipeline at West Delta, bringing online the first two development wells of the 2018 drilling program. The Company continues to focus on preventative maintenance and production optimization in order to mitigate future downtime. 

Costs and Expenses
Total lease operating expenses (“LOE”) in the second quarter of 2018 were $79.3 million, or $34.42 per BOE, which consisted of $72.1 million in direct lease operating expense, $2.1 million in workovers and $5.2 million in insurance expense. Total LOE for the second quarter of 2017 was $83.7 million, or $25.60 per BOE, and in the first quarter of 2018 was $82.0 million, or $34.22 per BOE.  Lease operating expense decreased quarter-over-quarter due to implemented cost savings initiatives and lower weather-related costs than in previous quarters.

Gathering and Transportation (“G&T”) expense for the second quarter of 2018 totaled $3.1 million, or $1.35 per BOE, compared to $2.7 million, or $0.82 per BOE, in second quarter of 2017, and $4.1 million, or $1.69 per BOE, in the first quarter of 2018.  EGC did not receive any additional refunds from the Office of Natural Resources Revenue (“ONRR”) during the quarter. The decline in G&T expense in the second quarter of 2018 compared with the prior quarter was primarily due to timing of project spending.

Second quarter 2018 Pipeline Facility Fee expense was $10.5 million, or $4.55 per BOE, compared to $10.5 million, or $3.21 per BOE, in the second quarter of 2017 and $10.5 million, or $4.38 per BOE, in the first quarter of 2018.

General and administrative (“G&A”) expense in the second quarter of 2018 was $15.6 million, or $6.76 per BOE, which includes $4.0 million in transaction fees.  During the second quarter of 2017, G&A expense totaled $20.7 million, $6.34 per BOE, which included $2.5 million in severance and separation costs.   First quarter 2018 G&A expense totaled $15.1 million, or $6.31 per BOE. G&A includes non-cash compensation costs of $2.9 million, or $1.24 per BOE, in the second quarter 2018 compared with $2.9 million, or $0.89 per BOE, in the second quarter of 2017, and $2.8 million, or $1.15 per BOE, in the first quarter of 2018. 

Depreciation, depletion and amortization (“DD&A”) expense was $27.6 million, or $11.96 per BOE, compared to $38.7 million, or $11.84 per BOE, in the second quarter of 2017.  First quarter 2018 DD&A was $27.4 million, or $11.44 per BOE.

Accretion of asset retirement obligation was $11.2 million, or $4.86 per BOE, during the second quarter of 2018, compared to $10.0 million, or $3.06 per BOE, in the second quarter of 2017.  First quarter 2018 accretion of asset retirement obligation expense was $11.1 million, or $4.64 per BOE.

EGC recorded no income tax expense or benefit during the second quarter 2018 or during prior comparable periods.

Commodity Hedging
During the second quarter of 2018, with no cash outlay, EGC unwound 3,000 BOPD fixed price swap contracts benchmarked to NYMEX-WTI for the period of April 2018 to June 2018 and added 3,000 BOPD costless collars benchmarked to ICE Brent with a floor price of $60.00 and a ceiling price of $82.00 for the same period. In addition, the Company entered into a fixed price swap contract benchmarked to ICE Brent to hedge 3,000 BOPD for the period of January 2019 to December 2019 with a contract price of $61.00.  As of June 30, 2018, EGC had fixed price swap contracts benchmarked to NYMEX-WTI to hedge a total of 8,000 BOPD of production for the remainder of the 2018 with an average fixed price swap of $50.68.  EGC does not have any hedges in place on natural gas production.

Operational Update and Capital Expenditure Program
During the second quarter of 2018, the Company incurred capital costs totaling $45.5 million of which $25.8 million was related to drilling, development and recompletion activities, $14.6 million related to plugging and abandonment (“P&A”) and $5.1 million related to capitalized G&A and other. Capital expenditures for the first quarter of 2018 totaled $21.8 million, of which $4.1 million was spent on drilling, development and recompletion activities, $12.8 million on P&A and $4.9 million on capitalized G&A and other.

During the second quarter of 2018, EGC spud and successfully completed two development wells and one rig recompletion.  The West Delta 74 C-41 ST01 Cato development well was brought online with initial production averaging approximately 600 BOE per day.  The West Delta 73 C-27 ST02 McCloud development well is currently being brought online. After a recompletion in the West Delta field, the rig moved to the South Timbalier field where EGC is currently drilling the South Timbalier 54 G-25 ST01 Koala well, that will be drilled to a total depth of 14,080 feet.  EGC has a 100% working interest in all of the wells mentioned above.

Balance Sheet and Liquidity
At June 30, 2018, EGC had approximately $58.4 million in borrowings and $201.5 million in letters of credit issued under its Exit Credit Facility and remained in compliance with the financial covenants under that facility.  During the quarter, the Company made a prepayment of $5.5 million toward the balance of the Exit Term Loan portion of its credit facility.  Liquidity at June 30, 2018 totaled approximately $110 million, which consists of cash and cash equivalents totaling $97.9 million and $12.5 million in borrowing capacity available under certain conditions.

Merger of Energy XXI Gulf Coast, Inc. and affiliates of Cox Oil LLC (“Cox”)
As previously announced on June 18, 2018, the EGC Board of Directors unanimously approved a merger transaction with affiliates of Cox, an independent, privately-held entity that owns and operates assets in the Gulf of Mexico.  Pursuant to the terms of the merger agreement, Cox will acquire all the outstanding shares of EGC common stock for $9.10 per fully diluted share in cash, for a total consideration of approximately $322 million. This represents a 21% premium to EGC’s closing share price on June 15, 2018. EGC reached this agreement after evaluating multiple transactions.

The closing of the transaction is subject to customary conditions, including obtaining the required vote from EGC’s stockholders. Obtaining financing is not a closing condition under the Cox merger agreement. The special stockholder meeting to vote on the adoption of the Cox merger agreement has been scheduled for September 6, 2018, at 9:00 a.m. Houston time.  The transaction is anticipated to close in the third quarter of 2018.

Conference Call
Due to the pending merger transaction between EGC and Cox, the Company will not be hosting a conference call this quarter.  An updated investor presentation in conjunction with this earnings release is available on the Company’s website at www.energyxxi.com under the Investor Relations section.

Non-GAAP Measures
Adjusted EBITDA is a supplemental non-GAAP financial measure.  Adjusted EBITDA is not a measure of net income or cash flows as determined by United States Generally Accepted Accounting Principles (“U.S. GAAP”).  EGC believes that Adjusted EBITDA is useful because it allows EGC to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. EGC excludes items such as asset retirement obligation accretion, unrealized derivative gains and losses, non-cash share-based compensation expense, non-cash deferred rent expense, severance expense and transaction costs from the calculation of Adjusted EBITDA. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with U.S. GAAP or as an indicator of its operating performance or liquidity. EGC’s computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

Cautionary Note Regarding Forward-Looking Statements

This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  These forward-looking statements relate to the pending merger transaction with Cox, as well as to EGC’s financial and operating performance on a stand-alone basis prior to the consummation of the merger or if the merger is not consummated.  These statements, including those relating to the intent, beliefs, plans, or expectations of EGC are based upon current expectations and are subject to a number of risks, uncertainties, and assumptions that could cause actual results to differ materially from the projections, anticipated results or other expectations expressed.  It is not possible to predict or identify all such factors and the following lists of factors should not be considered a complete statement of all potential risks and uncertainties.

With respect to the pending merger transaction between EGC and Cox, those factors include, but are not limited to: (i) the risk that the transaction may not be completed in the third quarter of 2018 or at all, which may adversely affect EGC’s business and the price of EGC’s stock; (ii) the failure to satisfy the conditions to the consummation of the transaction, including the adoption of the merger agreement by the EGC’s stockholders; (iii) the occurrence of any event, change or other circumstance that could give rise to the termination of the merger agreement; (iv) the effect of the announcement or pendency of the transaction, as well as the merger agreement’s limitations on EGC’s conduct of business, on EGC’s business relationships, operating results, and business generally; (v) risks that the proposed transaction disrupts EGC’s current plans and operations; (vi) the possibility that competing offers or acquisition proposals for EGC will be made; (vii) risks regarding the failure to obtain the necessary financing to complete the proposed transaction; and (viii) lawsuits related to the pending merger.

With respect to EGC’s financial and operating performance on a stand-alone basis prior to the consummation of the merger or if the merger is not consummated, those factors include, but are not limited to: (i) our ability to maintain sufficient liquidity and/or obtain adequate additional financing necessary to (A) maintain our infrastructure, particularly in light of its maturity, high fixed costs, and required level of maintenance and repairs compared to other GoM Shelf producers, (B) fund our operations and capital expenditures, (C) execute our business plan, develop our proved undeveloped reserves within five years and (D) meet our other obligations, including plugging and abandonment and decommissioning obligations; (ii) disruption of operations and damages due to maintenance or repairs of infrastructure and equipment and our ability to predict or prevent excessive resulting production downtime within our mature field areas; (iii) our future financial condition, results of operations, revenues, expenses and cash flows; (iv) our current or future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern; (v) recent changes in the composition of our board of directors; (vi) our inability to retain and attract key personnel; (vii) our ability to post collateral for current or future bonds or comply with any new regulations or Notices to Lessees and Operators imposed by the Bureau of Ocean Energy Management; (viii) our ability to comply with covenants under the three-year secured credit facility; and (ix) sustained declines in the prices we receive for our oil and natural gas production.

These risks and uncertainties could cause actual results, to differ materially from those described in the forward-looking statements. For a more detailed discussion of risk factors, please see the risk factors discussed in EGC’s periodic reports filed with the SEC. While EGC makes these statements and projections in good faith, EGC assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law.

About the Company

Energy XXI Gulf Coast, Inc. (EGC) is an exploration and production company headquartered in Houston, Texas that is engaged in the development, exploitation and acquisition of oil and natural gas properties in conventional assets in the U.S. Gulf Coast region, both offshore in the Gulf of Mexico and onshore in Louisiana and Texas.  To learn more, visit EGC’s website at www.energyxxi.com.

Investor Relations Contact
Al Petrie
Investor Relations Coordinator
713-351-3171
apetrie@energyxxi.com

Argelia Hernandez
Investor Relations Specialist
713-351-3175
ahernandez@energyxxi.com

ENERGY XXI GULF COAST, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

	June 30,				December 31,
	2018				2017
ASSETS	(Unaudited)
Current Assets
Cash and cash equivalents	$	97,900			$	151,729
Accounts receivable
Oil and natural gas sales		55,413				55,598
Joint interest billings, net		4,004				6,336
Other		19,920				15,726
Prepaid expenses and other current assets		11,873				21,602
Restricted cash		6,432				6,392
Total Current Assets		195,542				257,383
Property and Equipment
Oil and natural gas properties, net - full cost method of accounting, including $192.3 million and $200.2 million of unevaluated properties not being amortized at June 30, 2018 and December 31, 2017, respectively		773,153				764,922
Other property and equipment, net		8,269				10,120
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		781,422				775,042
Other Assets
Restricted cash		25,814				25,712
Other assets		29,468				18,845
Total Other Assets		55,282				44,557
Total Assets	$	1,032,246			$	1,076,982
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	79,154			$	85,122
Accrued liabilities		52,111				45,494
Asset retirement obligations		55,952				51,398
Derivative financial instruments		36,793				32,567
Current maturities of long-term debt		17				21
Total Current Liabilities		224,027				214,602
Long-term debt, less current maturities		58,413				73,952
Asset retirement obligations		625,496				613,453
Derivative financial instruments		6,305				-
Other liabilities		14,932				10,783
Total Liabilities		929,173				912,790
Commitments and Contingencies
Stockholders’ Equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding at June 30, 2018 and December 31, 2017		-				-
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,396,563 and 33,254,963 shares issued and outstanding at June 30, 2018 and December 31, 2017, respectively		334				333
Additional paid-in capital		916,525				911,144
Accumulated deficit		(813,786	)			(747,285	)
Total Stockholders’ Equity		103,073				164,192
Total Liabilities and Stockholders’ Equity	$	1,032,246			$	1,076,982

ENERGY XXI GULF COAST, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share information)
(Unaudited)

	Three Months Ended				Three Months Ended				Three Months Ended
	June 30,				March 31,				June 30,
	2018				2018				2017
Revenues
Oil sales	$	133,180			$	123,788			$	118,484
Natural gas liquids sales		1,076				1,343				2,370
Natural gas sales		6,261				8,382				13,753
Other revenue		2,267				1,492				-
Gain (loss) on derivative financial instruments		(26,045	)			(12,834	)			9,412
Total Revenues		116,739				122,171				144,019
Costs and Expenses
Lease operating		79,296				82,022				83,655
Production taxes		371				1,206				482
Gathering and transportation		3,119				4,056				2,678
Pipeline facility fee		10,494				10,494				10,494
Depreciation, depletion and amortization		27,555				27,411				38,685
Accretion of asset retirement obligations		11,197				11,118				9,984
General and administrative expense		15,568				15,132				20,716
Reorganization items		113				236				-
Total Costs and Expenses		147,713				151,675				166,694
Operating Loss		(30,974	)			(29,504	)			(22,675	)
Other Income (Expense)
Other income, net		191				143				80
Interest expense		(3,252	)			(3,694	)			(3,642	)
Total Other Expense, net		(3,061	)			(3,551	)			(3,562	)
Loss Before Income Taxes		(34,035	)			(33,055	)			(26,237	)
Income Tax Benefit		-				-				-
Net Loss	$	(34,035	)		$	(33,055	)		$	(26,237	)
Loss per Share
Basic and Diluted	$	(1.02	)		$	(0.99	)		$	(0.79	)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted		33,427				33,296				33,237

ENERGY XXI GULF COAST, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

	Three Months Ended				Three Months Ended				Three Months Ended
	June 30,				March 31,				June 30,
	2018				2018				2017
Cash Flows From Operating Activities
Net loss	$	(34,035	)		$	(33,055	)		$	(26,237	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		27,555				27,411				38,685
Change in fair value of derivative financial instruments		10,744				(213	)			(7,061	)
Accretion of asset retirement obligations		11,197				11,118				9,984
Amortization and write off of debt issuance costs and other		6				5				6
Deferred rent		2,239				1,930				2,016
Provision for loss on accounts receivable		-				-				300
Stock-based compensation		2,859				2,758				2,870
Changes in operating assets and liabilities
Accounts receivable		(3,621	)			1,944				11,849
Prepaid expenses and other assets		(4,888	)			3,680				4,165
Settlement of asset retirement obligations		(15,913	)			(18,804	)			(18,175	)
Accounts payable, accrued liabilities and other		14,427				(13,574	)			6,834
Net Cash Provided by (Used in) Operating Activities		13,631				(13,238	)			28,798
Cash Flows from Investing Activities
Capital expenditures		(18,977	)			(12,977	)			(5,391	)
Insurance payments received		-				-				(2,010	)
Proceeds from the sale of other property and equipment		38				250				10
Net Cash Used in Investing Activities		(18,939	)			(12,727	)			(7,391	)
Cash Flows from Financing Activities
Payments on long-term debt		(5,554	)			(10,002	)			(126	)
Other		(160	)			(75	)			(61	)
Net Cash Used in Financing Activities		(5,714	)			(10,077	)			(187	)
Net Increase (Decrease) in Cash and Cash Equivalents		(11,022	)			(36,042	)			21,220
Cash, Cash Equivalents and Restricted Cash, beginning of period		144,229				183,833				193,199
Cash, Cash Equivalents and Restricted Cash, end of period	$	133,207			$	147,791			$	214,419

ENERGY XXI GULF COAST, INC.
RECONCILIATION OF NON-GAAP MEASURES
(In Thousands, except per share information)
(Unaudited)

	Three Months Ended				Three Months Ended				Three Months Ended
	June 30,				March 31,				June 30,
	2018				2018				2017
Net loss	$	(34,035	)		$	(33,055	)		$	(26,237	)
Interest expense		3,252				3,694				3,642
Depreciation, depletion and amortization		27,555				27,411				38,685
Accretion of asset retirement obligations		11,197				11,118				9,984
Change in fair value of derivative financial instruments		10,744				(213	)			(7,061	)
Non-cash stock-based compensation		2,859				2,758				2,870
Deferred rent(1)		2,239				1,930				2,016
Severance costs		-				-				2,500
Transaction costs		3,961				-				-
Adjusted EBITDA	$	27,772			$	13,643			$	26,399

1. The deferred rent of approximately $2.2 million, $1.9 million and $2.0 million for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, respectively, is the non-cash portion of rent which reflects the extent to which our GAAP straight-line rent expense recognized exceeds our cash rent payments.
    

Operational Information

		Quarter Ended
			June 30,				March 31,				June 30,
Operating Highlights			2018				2018				2017
		(In thousands, except per unit amounts)
Operating revenues
Oil sales		$	133,180			$	123,788			$	118,484
Natural gas liquids sales			1,076				1,343				2,370
Natural gas sales			6,261				8,382				13,753
Other revenue			2,267				1,492				-
Gain (loss) on derivative financial instruments			(26,045	)			(12,834	)			9,412
Total revenues			116,739				122,171				144,019
Percentage of oil revenues prior to gain (loss) on derivative financial instruments			93%				92%				88%
Operating expenses
Lease operating expense
Insurance expense			5,177				5,195				7,101
Workovers			2,054				2,524				4,535
Direct lease operating expense			72,065				74,303				72,019
Total lease operating expense			79,296				82,022				83,655
Production taxes			371				1,206				482
Gathering and transportation			3,119				4,056				2,678
Pipeline facility fee			10,494				10,494				10,494
Depreciation, depletion and amortization			27,555				27,411				38,685
Accretion of asset retirement obligations			11,197				11,118				9,984
Impairment of oil and natural gas properties			-				-				-
Goodwill impairment			-				-				-
General and administrative			15,568				15,132				20,716
Reorganization items			113				236				-
Total operating expenses			147,713				151,675				166,694
Operating loss		$	(30,974	)		$	(29,504	)		$	(22,675	)
Sales volumes per day
Oil (MBbls)			21.1				21.1				26.8
Natural gas liquids (MBbls)			0.3				0.4				1.0
Natural gas (MMcf)			23.6				30.6				48.9
Total (MBOE)			25.3				26.6				35.9
Percent of sales volumes from oil			83%				79%				75%
Average sales price
Oil per Bbl		$	69.54			$	65.09			$	48.57
Natural gas liquid per Bbl			34.98				37.01				27.37
Natural gas per Mcf			2.92				3.04				3.09
Other revenue per BOE			0.98				0.62				-
(Loss) gain on derivative financial instruments per BOE			(11.30	)			(5.35	)			2.88
Total revenues per BOE			50.67				50.97				44.08
Operating expenses per BOE
Lease operating expense
Insurance expense			2.25				2.17				2.17
Workovers			0.89				1.05				1.39
Direct lease operating expense			31.28				31.00				22.04
Total lease operating expense per BOE			34.42				34.22				25.60
Production taxes			0.16				0.50				0.15
Gathering and transportation			1.35				1.69				0.82
Pipeline facility fee			4.55				4.38				3.21
Depreciation, depletion and amortization			11.96				11.44				11.84
Accretion of asset retirement obligations			4.86				4.64				3.06
General and administrative			6.76				6.31				6.34
Reorganization items			0.05				0.10				-
Total operating expenses per BOE			64.11				63.28				51.02
Operating loss per BOE		$	(13.44	)		$	(12.31	)		$	(6.94	)