Energy XXI Gulf Coast Announces First Quarter 2018 Financial and Operational Results

HOUSTON, May 10, 2018 (GLOBE NEWSWIRE) -- Energy XXI Gulf Coast, Inc. (“EGC” or the “Company”) (NASDAQ:EGC) today reported financial and operational results for the first quarter 2018.  In a separate press release, the Company also announced that it has signed a term sheet for a transaction to divest its current non-core asset portfolio and related asset retirement obligations.

An updated investor presentation in conjunction with this earnings release and the proposed transaction is available on the Company’s website at www.energyxxi.com under the Investor Relations section.

First Quarter 2018 Highlights and Recent Key Items:

• Produced an average of approximately 26,600 barrels of oil equivalent (“BOE”) per day, of which 79% was oil, above the midpoint of guidance
• Incurred a net loss of $33.1 million, or $0.99 per share, which included a $12.8 million loss on derivative financial instruments
• Generated Adjusted EBITDA of $13.6 million, an increase of $2.8 million from fourth quarter 2017
•  Entered into discussions with the owner and lessor of the Grand Isle Gathering System (“GIGS”) regarding, among other things, a possible restructuring of the GIGS lease
• Announced signing a non-binding term sheet for the proposed strategic disposition of non-core assets and related asset retirement obligations to Orinoco Natural Resources in a separate press release today
• Welcomed two new Board members - Gary Hanna (Chairman of the Board) and Gabriel L. Ellisor
• Estimated second quarter production to average 24,500 to 26,000 barrels of oil per day, due to increased downtime associated with shut-ins due to facility improvements and pipeline issues
• Provided updated results on the West Delta 31 High Tide well which is currently producing approximately 1,000 barrels of oil per day and about 2.0 million cubic feet of natural gas (“MMCF”) per day, exceeding pre-drill expectations
• Drilled and completed the first well in the 2018 drilling program, the West Delta 73 McCloud well, below pre-drill capital estimates, and with first production expected in May

For the first quarter of 2018, EGC reported a net loss of $33.1 million, or $0.99 loss per diluted share, which included a $12.8 million loss on derivative financial instruments. In the first quarter of 2017, the Company reported a net loss of $64.5 million, or $1.94 loss per diluted share, which included a $40.8 million non-cash ceiling test impairment charge and a $3.7 million gain on derivative financial instruments.  In the fourth quarter of 2017, the Company reported a net loss of $215.1 million, or $6.47 loss per diluted share, which included a $145.1 million non-cash ceiling test impairment charge and a $33.3 million loss on financial derivative instruments.

Adjusted EBITDA totaled $13.6 million for the first quarter 2018, an increase of $2.8 million compared to $10.8 million in the fourth quarter of 2017.

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 “While first quarter results were in line with our prior guidance, operationally we continue to battle downtime and weather issues, in particular pipeline downtime, which reduced volumes in the first quarter and into mid-May.  We are working to restore production and implement permanent solutions to our pipeline issues which should positively impact volumes and uptime in the future. We remain focused on base optimization, preventative maintenance and reducing downtime to maximize our production and increase our ability to generate EBITDA. We are encouraged by the pre-completion shows in the McCloud well, and the performance of the High Tide well.  We are excited by the potential results of the remaining wells in our 2018 drilling program, in particular the two planned exploitation wells which if successful, could have a meaningful impact on our reserves and production. We are optimistic about our future potential and our ability to enhance shareholder value.”

Production and Pricing
In the first quarter of 2018, the Company produced and sold approximately 26,600 net BOE per day, above the midpoint of its guidance range. EGC continued to benefit from the impact of higher realized oil prices (before the effect of derivatives) that were about 4% higher than average WTI prices during the quarter due to the positive differentials that EGC receives on its oil sales.

		Quarter Ended
		March 31,			December 31		March 31,
		2018			2017		2017
		(In thousands, except per unit amounts)
Sales volumes per day
Oil (MBbls)			21.1		21.3			29.1
Natural gas liquids (MBbls)			0.4		0.6			0.9
Natural gas (MMcf)			30.6		34.5			65.9
Total (MBOE)			26.6		27.6			41.0
Percent of sales volumes from oil			79%		77%			71%
Average sales price before hedging impact
Oil per Bbl		$	65.09	$	59.27		$	51.11
Natural gas liquid per Bbl			37.01		33.28			27.52
Natural gas per Mcf			3.04		2.97			3.10

When compared with the fourth quarter 2017, first quarter higher realized prices were offset by higher production downtime primarily related to continued production equipment maintenance, pipeline shut-ins, facility-related unscheduled downtime, severe winter weather and natural decline.  Preventative maintenance continues to be an operating priority to ensure the safety of employees, reduce environmental impact, and improve production uptime.

In the first quarter of 2018 and into May, EGC experienced increased downtime associated with temporary shut-ins due to facility improvements as well as pipeline problems. April production was reduced by approximately 4,800 BOE per day from these shut-ins. As a result, second quarter production is expected to average 24,500 to 26,000 BOE per day. In early May, we began restoration of production through the affected pipelines and with the continued strong production from the High Tide well, current daily production is averaging about 27,000 BOE per day. The Company had previously budgeted funds to fully replace one of these pipelines that has faced ongoing issues at West Delta and is currently working on its timely replacement in the fall of 2018 to mitigate future downtime. 

Costs and Expenses
Total lease operating expenses (“LOE”) in the first quarter of 2018 were $82.0 million, or $34.22 per BOE, which consisted of $74.3 million in direct lease operating expense, $2.5 million in workovers and $5.2 million in insurance expense. Total LOE for the first quarter of 2017 was $77.3 million, or $20.96 per BOE, and in the fourth quarter of 2017 was $80.9 million, or $31.90 per BOE.  Lease operating expense increased year-over-year primarily due to increased well activity, renewed maintenance initiatives and severe weather-related costs.

Gathering and Transportation (“G&T”) expense for the first quarter of 2018 totaled $4.1 million, or $1.69 per BOE, compared to $11.2 million, or $3.04 per BOE, in first quarter 2017 and $10.2 million, or $4.02 per BOE, in fourth quarter 2017.  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 first quarter of 2018 compared with prior quarters was primarily due to timing of maintenance costs that are now forecasted to occur in the second half of 2018, as well as reduced marketing costs due to lower production volumes.

First quarter 2018 Pipeline Facility Fee expense was $10.5 million ($4.38 per BOE), compared to $10.5 million ($4.14 per BOE) in the fourth quarter of 2017. Given the quality of the long-term reserves behind GIGS, CorEnergy Infrastructure Trust, Inc.  (“CorEnergy”), the owner and lessor of GIGS that transmits much of EGC’s core area production, has entered into discussions with EGC regarding among other things, a potential lease restructuring, that preserve the long-term value of GIGS and seek to support EGC’s further recovery efforts and future success. There can be no assurance that any such lease restructuring transaction will be consummated or, if consummated, when that transaction will occur or on what terms.

General and administrative (“G&A”) expense in the first quarter of 2018 was $15.1 million, or $6.31 per BOE, compared to $21.6 million, or $5.86 per BOE, in the first quarter 2017.  G&A includes non-cash compensation costs of $2.8 million ($1.15 per BOE) in the first quarter 2018 compared with $0.9 million ($0.24 per BOE) in the first quarter 2017.  For the fourth quarter of 2017, G&A expense totaled $14.7 million, or $5.80 per BOE.  EGC continues to benefit from lower G&A costs as a result of cost reduction initiatives.

Depreciation, depletion and amortization (“DD&A”) expense was $27.4 million, or $11.44 per BOE, compared to $41.9 million, or $11.36 per BOE, in the first quarter of 2017.  Fourth quarter 2017 DD&A was $33.4 million, or $13.18 per BOE.

Accretion of asset retirement obligation was $11.1 million during the first quarter of 2018, compared to $13.1 million in the first quarter 2017.  Fourth quarter 2017 expense was $10.0 million, or $3.93 per BOE.

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

Commodity Hedging
In April 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.  At the end of the first quarter of 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, and fixed price swap contracts benchmarked to LLS-Argus for 2,000 BOPD with an average fixed price of $55.45 for the period of April to June 2018, and 2,500 BOPD fixed price swap contracts benchmarked to ICE-Brent with an average fixed price of $56.59 for the period April to June 2018.  EGC does not have any hedges in place on natural gas production.

Operational Update and Capital Expenditure Program
During the first quarter of 2018, the Company incurred capital costs totaling $21.8 million of which $4.1 million was related to drilling, development and recompletion activities, $12.8 million related to plugging and abandonment (“P&A”) and $4.9 million related to capitalized G&A and other. A delay in the arrival of the rig contracted for the 2018 drilling program reduced anticipated first quarter capital expenditures.  Capital expenditures for the fourth quarter of 2017 totaled $26.9 million, of which $10.6 million was spent on drilling, development and recompletion activities, $13.3 million on P&A and $3.0 million on capitalized G&A and other.

EGC spud and successfully completed the first well of the 2018 drilling program in April, the West Delta 73 C-27 McCloud, a development well location, which is expected to begin production in May.  The West Delta 74 C-41ST Cato, also a development well, was spud in early May, and is currently drilling to a total depth of 11,400 feet.  After completion of the Cato well, the Company plans to recomplete the D-20 ST well in the same field.  As previously reported, the High Tide well, which was spud in June 2017, transitioned to oil earlier this year and is currently producing greater than 1,000 barrels of oil and 2.1 MMCF per day.   EGC has a 100% working interest in all of the wells mentioned above.

Capital expenditures for the second quarter are expected to be in the range of $50 million to $60 million, of which $22 million to $26 million is related to drilling and recompletion activities, and $26 million to $32 million on P&A. An increase in capital costs in the second quarter is anticipated due to the increase in drilling and completion activities, as well as additional P&A activities.  Capital expenditures for 2018 remain within the expected range of $145 million to $175 million, which include $55 million to $65 million related to drilling six new wells, $10 million to $15 million for planned facility improvements, and $8 million to $10 million for seven to nine recompletions, and $50 million to $60 million for P&A activities. The Company continues to evaluate its inventory to high grade its program that would have the most meaningful impact to current production and arrest natural decline.

Balance Sheet and Liquidity
At March 31, 2018, EGC had approximately $64 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 $10 million toward the balance of the Exit Term Loan portion of its credit facility.  Liquidity at March 31, 2018 totaled approximately $124.6 million, which consists of cash and cash equivalents totaling $112.1 million and $12.5 million in borrowing capacity available under certain conditions.

Conference Call
The Company will host a conference call to discuss its first quarter operating results and the proposed transaction to divest non-core assets this morning, Thursday, May 10, 2018, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time).  Interested parties may participate by dialing (877) 794-3620.  International parties may dial (631) 813-4724.  The confirmation code is 1249348.  This call will also be webcast on EGC’s website at www.energyxxi.com. A replay of the call will be archived and available on the website shortly after the live call.

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 property and inventory impairments, asset retirement obligation accretion, unrealized derivative gains and losses, non-cash share-based compensation expense, non-cash deferred rent expense and restructuring and severance expense 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 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 list of factors should not be considered a complete statement of all potential risks and uncertainties, including, but not limited to: (i) our ability to maintain sufficient liquidity and/or obtain adequate additional financing necessary to fund our operations, capital expenditures and to execute our business plan, develop our proved undeveloped reserves within five years and to meet our other obligations, including plugging and abandonment and decommissioning obligations; (ii) our new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value could vary significantly from current or future estimates; (iii) our future financial condition, results of operations, revenues, expenses and cash flow; (iv) our current or future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern; (v) the effects of the departure of our senior leaders and the hiring of a new senior management team on our employees, suppliers, regulators and business counterparties; (vi) recent changes (including announced future changes) in the composition of our board of directors; (vii) our inability to retain and attract key personnel; (viii) our ability to post collateral for current or future bonds or comply with any new regulations or Notices to Lessees and Operator; (ix) our ability to comply with covenants under the three-year secured credit facility; (x) changes in our business strategy; (xi) sustained or further declines in the prices we receive for our oil and natural gas production; and (xii) other risks and uncertainties.  These risks and uncertainties could cause actual results, including project plans and related expenditures and resource recoveries, 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)

	March 31,				December 31,
	2018				2017
ASSETS	(Unaudited)
Current Assets
Cash and cash equivalents	$	112,062			$	151,729
Accounts receivable
Oil and natural gas sales		54,662				55,598
Joint interest billings, net		5,764				6,336
Other		15,290				15,726
Prepaid expenses and other current assets		12,147				21,602
Restricted cash		6,409				6,392
Total Current Assets		206,334				257,383
Property and Equipment
Oil and natural gas properties, net - full cost method of accounting, including $195.9 million and $200.2 million of unevaluated properties not being amortized at March 31, 2018 and December 31, 2017, respectively		759,483				764,922
Other property and equipment, net		9,157				10,120
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		768,640				775,042
Other Assets
Restricted cash		25,758				25,712
Other assets		24,303				18,845
Total Other Assets		50,061				44,557
Total Assets	$	1,025,035			$	1,076,982
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	66,769			$	85,122
Accrued liabilities		41,332				45,494
Asset retirement obligations		53,415				51,398
Derivative financial instruments		32,354				32,567
Current maturities of long-term debt		5,571				21
Total Current Liabilities		199,441				214,602
Long-term debt, less current maturities		58,407				73,952
Asset retirement obligations		620,105				613,453
Other liabilities		12,673				10,783
Total Liabilities		890,626				912,790
Commitments and Contingencies
Stockholders’ Equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding at March 31, 2018 and December 31, 2017		-				-
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,268,478 and 33,254,963 shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively		333				333
Additional paid-in capital		913,828				911,144
Accumulated deficit		(779,752	)			(747,285	)
Total Stockholders’ Equity		134,409				164,192
Total Liabilities and Stockholders’ Equity	$	1,025,035			$	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
	March 31,					December 31,				March 31,
	2018					2017				2017
Revenues
Oil sales	$	123,788				$	115,948			$	133,793
Natural gas liquids sales		1,343					1,736				2,227
Natural gas sales		8,382					9,423				18,368
Other revenue		1,492					-				-
(Loss) gain on derivative financial instruments		(12,834	)				(33,269	)			3,698
Total Revenues		122,171					93,838				158,086
Costs and Expenses
Lease operating		82,022					80,927				77,267
Production taxes		1,206					163				239
Gathering and transportation		4,056					10,207				11,222
Pipeline facility fee		10,494					10,494				10,494
Depreciation, depletion and amortization		27,411					33,439				41,896
Accretion of asset retirement obligations		11,118					9,962				13,081
Impairment of oil and natural gas properties		-					145,086				40,774
General and administrative expense		15,132					14,711				21,604
Reorganization items		236					311				2,244
Total Costs and Expenses		151,675					305,300				218,821
Operating Loss		(29,504	)				(211,462	)			(60,735	)
Other Income (Expense)
Other income, net		143					100				22
Interest expense		(3,694	)				(3,707	)			(3,834	)
Total Other Expense, net		(3,551	)				(3,607	)			(3,812	)
Loss Before Income Taxes		(33,055	)				(215,069	)			(64,547	)
Income Tax Benefit		-					-				-
Net Loss	$	(33,055	)			$	(215,069	)		$	(64,547	)
Loss per Share
Basic and Diluted	$	(0.99	)			$	(6.47	)		$	(1.94	)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted		33,296					33,245				33,228

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

	Three Months Ended					Three Months Ended				Three Months Ended
	March 31,					December 31,				March 31,
	2018					2017				2017
Cash Flows From Operating Activities
Net loss	$	(33,055	)			$	(215,069	)		$	(64,547	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		27,411					33,439				41,896
Impairment of oil and natural gas properties		-					145,086				40,774
Change in fair value of derivative financial instruments		(213	)				28,691				(3,409	)
Accretion of asset retirement obligations		11,118					9,962				13,081
Amortization of debt issuance costs		5					6				-
Deferred rent		1,930					1,930				2,015
Provision for loss on accounts receivable		-					300				-
Stock-based compensation		2,758					2,745				852
Changes in operating assets and liabilities
Accounts receivable		1,944					(4,720	)			15,555
Prepaid expenses and other assets		3,680					(6,636	)			6,969
Settlement of asset retirement obligations		(18,804	)				(16,036	)			(9,316	)
Accounts payable, accrued liabilities and other		(13,574	)				12,127				(57,572	)
Net Cash Used in Operating Activities		(16,800	)				(8,175	)			(13,702	)
Cash Flows from Investing Activities
Capital expenditures		(12,977	)				(16,196	)			(19,105	)
Insurance payments received		-					-				2,051
Proceeds from the sale of other property and equipment		250					2,793				1,269
Net Cash Used in Investing Activities		(12,727	)				(13,403	)			(15,785	)
Cash Flows from Financing Activities
Payments on long-term debt		(10,002	)				(6	)			(602	)
Other		(75	)				-				-
Net Cash Used in Financing Activities		(10,077	)				(6	)			(602	)
Net Decrease in Cash, Cash Equivalents and Restricted Cash		(39,604	)				(21,584	)			(30,089	)
Cash, Cash Equivalents and Restricted Cash, beginning of period		183,833					205,417				223,288
Cash, Cash Equivalents and Restricted Cash, end of period	$	144,229				$	183,833			$	193,199

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
	March 31,				December 31,				March 31,
	2018				2017				2017
Net loss	$	(33,055	)		$	(215,069	)		$	(64,547	)
Interest expense		3,694				3,707				3,834
Depreciation, depletion and amortization		27,411				33,439				41,896
Impairment of oil and natural gas properties		-				145,086				40,774
Accretion of asset retirement obligations		11,118				9,962				13,081
Change in fair value of derivative financial instruments		(213	)			28,691				(3,409	)
Non-cash stock-based compensation		2,758				2,745				852
Deferred rent(1)		1,930				1,930				2,015
Severance costs		-				325				6,200
Adjusted EBITDA	$	13,643			$	10,816			$	40,696

(1)	The deferred rent of approximately $1.9 million, $1.9 million and $2.0 million for the three months ended March 31, 2018, December 31, 2017 and March 31, 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
		March 31,				December 31				March 31,
Operating Highlights		2018				2017				2017
		(In thousands, except per unit amounts)
Operating revenues
Oil sales		$	123,788			$	115,948			$	133,793
Natural gas liquids sales			1,343				1,736				2,227
Natural gas sales			8,382				9,423				18,368
Other revenue			1,492				-				-
(Loss) gain on derivative financial instruments			(12,834	)			(33,269	)			3,698
Total revenues			122,171				93,838				158,086
Percentage of oil revenues prior to (loss) gain on derivative financial instruments			92%				91%				87%
Operating expenses
Lease operating expense
Insurance expense			5,195				5,121				6,250
Workovers			2,524				3,023				2,565
Direct lease operating expense			74,303				72,783				68,452
Total lease operating expense			82,022				80,927				77,267
Production taxes			1,206				163				239
Gathering and transportation			4,056				10,207				11,222
Pipeline facility fee			10,494				10,494				10,494
Depreciation, depletion and amortization			27,411				33,439				41,896
Accretion of asset retirement obligations			11,118				9,962				13,081
Impairment of oil and natural gas properties			-				145,086				40,774
General and administrative			15,132				14,711				21,604
Reorganization items			236				311				2,244
Total operating expenses			151,675				305,300				218,821
Operating loss		$	(29,504	)		$	(211,462	)		$	(60,735	)
Sales volumes per day
Oil (MBbls)			21.1				21.3				29.1
Natural gas liquids (MBbls)			0.4				0.6				0.9
Natural gas (MMcf)			30.6				34.5				65.9
Total (MBOE)			26.6				27.6				41.0
Percent of sales volumes from oil			79%				77%				71%
Average sales price
Oil per Bbl		$	65.09			$	59.27			$	51.11
Natural gas liquid per Bbl			37.01				33.28				27.52
Natural gas per Mcf			3.04				2.97				3.10
Other revenue per BOE			0.62				-				-
(Loss) gain on derivative financial instruments per BOE			(5.35	)			(13.12	)			1.00
Total revenues per BOE			50.97				36.99				42.88
Operating expenses per BOE
Lease operating expense
Insurance expense			2.17				2.02				1.70
Workovers			1.05				1.19				0.70
Direct lease operating expense			31.00				28.69				18.56
Total lease operating expense per BOE			34.22				31.90				20.96
Production taxes			0.50				0.06				0.06
Gathering and transportation			1.69				4.02				3.04
Pipeline facility fee			4.38				4.14				2.85
Depreciation, depletion and amortization			11.44				13.18				11.36
Accretion of asset retirement obligations			4.64				3.93				3.55
Impairment of oil and natural gas properties			-				57.20				11.06
General and administrative			6.31				5.80				5.86
Reorganization items			0.10				0.12				0.61
Total operating expenses per BOE			63.28				120.35				59.35
Operating loss per BOE		$	(12.31	)		$	(83.36	)		$	(16.47	)