updated 2/3/2011 11:15:45 PM ET 2011-02-04T04:15:45

  • Acquisition, equity and debt deals transform operations and balance sheet
  • Exploration and development projects show encouraging results

HOUSTON, Feb. 3, 2011 (GLOBE NEWSWIRE) -- Energy XXI (Bermuda) Limited (Nasdaq:EXXI) (LSE:EXXI) today announced fiscal second-quarter results for the period ended Dec. 31, 2010 and provided an operational update.

For the 2011 fiscal second quarter, Energy XXI reported earnings before other income (expense), taxes, depreciation, depletion and amortization (adjusted EBITDA) of $107.5 million, compared with $66.3 million in the 2010 fiscal second quarter. The company had a net loss attributable to common shareholders for the 2011 fiscal second quarter of $11.3 million ($0.17 per share) on revenues of $174 million and production of 29,400 barrels of oil equivalent per day (BOE/d). These results reflect a partial contribution from the company's Dec. 17, 2010 acquisition of certain Gulf of Mexico properties. The results also include a number of non-recurring charges associated with the company's acquisition and financing activities, totaling $26.9 million after-tax for the quarter. In the 2010 fiscal second quarter, net income attributable to common shareholders was $16.1 million, or $0.46 per share, on revenues of $124.5 million and production of 20,900 BOE/d. The 2010 fiscal second-quarter results included a $17.8 million after-tax non-cash gain due to the retirement of bonds previously repurchased at a discount to face value.

"The company's operational and financial profile has been transformed in the past few months," Energy XXI Chairman and CEO John Schiller said. "Since October, we have announced and closed the largest acquisition in the company's history, converted most of our 7.25% preferred shares to common, retired all of our 16% notes, retired 17 percent of our 10% notes, completed a $556 million equity raise and issued $750 million of senior notes at our lowest interest rate to date.  In addition, we've made significant progress on our deep and ultra-deep drilling programs, with encouraging results. As a result, Energy XXI today is in an excellent position to continue growing and delivering returns to shareholders."

Production Update

Production volumes in January 2011 averaged approximately 43,300 BOE/d, positively affected by the December acquisition of Gulf of Mexico properties, partially offset by temporary shut-ins caused by a number of factors, including freezing production equipment and third-party pipeline outages. Current production approximates 45,000 BOE/d, with the capacity to produce approximately 46,000 BOE/d.

Exploration and Development Activity

Within the shallow-water, ultra-deep Gulf of Mexico shelf program, the McMoRan-operated partnership (in which Energy XXI has various interests) has identified 15 sub-salt prospects near existing infrastructure. The partnership's current drilling activity includes the Blackbeard East and Lafitte exploratory wells and the delineation well at Davy Jones.

Earlier today, McMoRan announced results from interim logging operations at the Davy Jones offset appraisal well located on South Marsh Island Block 234 in 20 feet of water. The offset well is drilling below 27,900 feet. Preliminary data from wireline logs over the interval from 25,400 feet to 27,300 feet, which continue to be evaluated, indicated over 200 feet of gross sand and approximately 100 net feet of sand, based on intermittent porosity data available, in multiple Wilcox zones that appear to be hydrocarbon bearing. Additional data will be required to complete the evaluation. Paleo and log data indicate the offset well to be approximately 1,300 feet structurally high (up dip) to the Davy Jones discovery well and confirm the major structural features of the Davy Jones prospect. All but one of the sands in the discovery well appear to be present in the offset well, which would confirm sand continuity on the Davy Jones feature. This information also suggests that the Wilcox sands at Davy Jones could be sheet sands rather than channel sands, and could be present at other prospects on the partnership's acreage position within the Davy Jones trend. These results support the wedge effect seen on other large sub-salt structures in the Gulf of Mexico, where sands generally thicken on the flanks of the structure.   The Davy Jones offset well is located two and a half miles southwest of the discovery well. Based on analogies with a number of other large sub-surface structures in the Gulf of Mexico, there is potential for thicker sands on the northern part of the structure, which is closer to the depositional source.

The Davy Jones offset well is being deepened to evaluate additional objectives, including possibly the Upper Cretaceous (Tuscaloosa) sections. Paleo data at 27,742 feet indicate the well is in the Midway formation, which is a geologic interval below the Wilcox and above the Upper Cretaceous (Tuscaloosa). If present in deeper horizons at Davy Jones, the Upper Cretaceous (Tuscaloosa) section could be correlative with the prolific Tuscaloosa trend onshore south Louisiana.

As previously reported, in February 2010, the Davy Jones discovery well on South Marsh Island Block 230 was drilled to a total depth of 29,000 feet and logs confirmed 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands.  In March 2010, a production liner was set and the well was temporarily abandoned until necessary equipment for the completion is available.  Long-lead-time equipment needed to complete, test and produce the well has been ordered, with first flow expected by calendar year-end 2011.

Davy Jones involves a large structure encompassing four lease blocks (20,000 acres). Energy XXI has a 15.8 percent working interest and 12.6 percent net revenue interest in Davy Jones. The company's investment in both wells at Davy Jones to date has totaled about $37 million.

The Blackbeard East exploration well, located in 80 feet of water on South Timbalier Block 144, commenced drilling on March 8, 2010 and is currently drilling below 32,600 feet towards a revised permitted depth of 34,000 feet.  Recent wireline logs indicate Blackbeard East has encountered hydrocarbon-bearing sands in the Oligocene (Frio) section with good porosity below 30,000 feet. This is the first hydrocarbon-bearing Frio sand encountered either on the Gulf of Mexico Shelf or in the deepwater offshore Louisiana. This Frio sand section is geologically older than the section drilled at Blackbeard West (33,000 feet). The Frio trend is prolific onshore Louisiana and along the Texas coast. Seismic data on Blackbeard East indicates the potential for significantly thicker sands on the flanks of the structure, similar to those confirmed in major deepwater discoveries by other industry participants, including the K2 field, and down-dip drilling locations are being considered. The Frio sand section found below 30,000 feet is in addition to the previously announced 178 net feet of hydrocarbons discovered in the Miocene above 25,000 feet at Blackbeard East.  In calendar 2011, a 25,000 foot offset appraisal well is expected to be drilled to further evaluate and delineate theses zones in the Upper and Middle Miocene, which appear to be similar to the structures identified in the Auger and Cardamom discoveries drilled in the Gulf of Mexico Flex trend by other industry participants. Energy XXI has an 18 percent working interest and 14.35 percent net revenue interest in Blackbeard East. The company's investment in the well to date has totaled about $22 million.

The Lafitte exploration well commenced drilling on Oct. 3, 2010 and is currently drilling below 17,900 feet towards a proposed total depth of 29,950 feet, targeting Middle and Deep Miocene objectives and possibly Oligocene (Frio) sections below the salt weld.  Lafitte is located on Eugene Island Block 223 in 140 feet of water. Energy XXI has an 18 percent working interest and a 14.6 percent net revenue interest. The company's investment in the well to date has totaled about $6 million.

Onshore Louisiana, Energy XXI is participating in the McMoRan-operated Valentine Pontiff well, an offset to the 2007 Laphroaig discovery. The well commenced drilling Sept. 24, 2010 and was drilled to 18,366 feet. Gamma ray and resistivity data obtained from log-while-drilling (LWD) tools indicated multiple possible hydrocarbon-bearing zones measuring 140 net feet in aggregate. The well was subsequently by-passed at 16,867 feet due to a mechanical issue and drilled to 18,000 feet. LWD tools have now confirmed the first zone of pay, with porosity in excess of 30 percent, and drilling is continuing towards a proposed depth of 20,000 feet for the other zones seen previously and additional targets, including the MA-11 sand that produced more than 35 billion cubic feet equivalent in the discovery well. Energy XXI has an 18.75 percent working interest and a 15 percent net revenue interest in the well, where the company's investment to date has totaled approximately $3 million.

Within the company's core producing fields offshore Louisiana, recompletion and development drilling has continued. At the East Cameron 334 field, Energy XXI recompleted the EC 334 #F-1 well in the M-3C sand at 14,672 feet and the EC 334 #E1 well in the M‑4 sand at 15,346 feet. The wells were brought online at a combined 9.5 million cubic feet per day (MMcf/d) of gas and 462 barrels per day (Bbl/d) of oil (gross), for an equivalent rate of 1,501 BOE/d net to the company. Energy XXI has a 72 percent working interest and a 60 percent net revenue interest in the #F-1 well and a 100 percent working interest and an 83 percent net revenue interest in the #E1 well.

At the Apache-operated Eugene Island 330 field, the first three wells in a field-wide redevelopment program have been brought online. The EI 330 #B16 ST well was completed in the HB-1 sand at 7,086 feet. The EI 330 #B9 ST was dual completed in the GA-2 and HB-3 sands at 4,354 feet and 5,034 feet, respectively. The EI 330 #B14 ST was completed in the HB-3 sand at 5,025 feet and currently is being dual completed in the HB-1 sand at 4,888 feet. The wells were placed online at a combined 1,544 Bbl/d of oil and 2.6 MMcf/d of gas (gross), for a rate of 582 BOE/d net.  Energy XXI has a 35 percent working interest and a 29 percent net revenue interest in the field.

Capital Expenditures

During the 2011 fiscal second quarter, capital expenditures, excluding acquisitions but including plug-and-abandonment costs, totaled $66.6 million, with $30.3 million in exploration and $36.3 million in development and other investments. The board of directors has approved an increase in the fiscal 2011 capital program to $340 million, up from the original $250 million, largely related to the acquired Gulf of Mexico properties and the shallow-water ultra-deep drilling program.

Forward-Looking Statements

All statements included in this release relating to future plans, projects, events or conditions and all other statements other than statements of historical fact included in this release are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon current expectations and are subject to a number of risks, uncertainties and assumptions, including changes in long-term oil and gas prices or other market conditions affecting the oil and gas industry, reservoir performance, the outcome of commercial negotiations and changes in technical or operating conditions, among others, that could cause actual results, including project plans and related expenditures and resource recoveries, to differ materially from those described in the forward-looking statements. Energy XXI assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law.

Competent Person Disclosure

The technical information contained in this announcement relating to operations adheres to the standard set by the Society of Petroleum Engineers. Tom O'Donnell, Vice President of Exploitation, a registered Petroleum Engineer, is the qualified person who has reviewed and approved the technical information contained in this announcement.

About the Company

Energy XXI is an independent oil and natural gas exploration and production company whose growth strategy emphasizes acquisitions, enhanced by its value-added organic drilling program. The company's properties are located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore. Seymour Pierce is Energy XXI's listing broker in the United Kingdom.  To learn more, visit the Energy XXI website at www.EnergyXXI.com .

The Energy XXI logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=3587

(In Thousands, except per share information)

As required under Regulation G of the Securities Exchange Act of 1934, provided below are reconciliations of net income to the following non-GAAP financial measure: Adjusted EBITDA. The company uses this non-GAAP measure as a key metric for the management of the company and to demonstrate the company's ability to internally fund capital expenditures and service debt.

  Three Months Ended Six Months Ended
  December 31, December 31,
  2010 2009 2010 2009
Net Income as Reported $10,934 $16,446 $11,067 $4,146
Total other (income) expense 31,627 (3,313) 53,097 15,663
Depreciation, depletion and amortization 62,922 44,972 116,999 80,323
Income tax expense 2,011 8,206 2,030 17,453
Adjusted EBITDA $107,494 $66,311 $183,193 $117,585
Adjusted EBITDA Per Share        
Basic $1.64 $1.96 $3.15 $3.74
Diluted $1.64 $1.85 $3.13 $3.60
Weighted Average Number of Common Shares Outstanding        
Basic 65,479 33,788 58,241 31,470
Diluted 65,670 35,815 58,500 32,627
(In Thousands, except share information)
  December 31, June 30,
  2010 2010
ASSETS (Unaudited)  
Current Assets    
Cash and cash equivalents $39,991 $14,224
Accounts receivable    
Oil and natural gas sales 112,017 68,675
Joint interest billings 5,544 4,388
Insurance and other 474 4,471
Prepaid expenses and other current assets 36,757 34,479
Derivative financial instruments 19,757
Total Current Assets 194,783 145,994
Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment    
Oil and natural gas properties - full cost method of accounting, including $448.6 million and $144.3 million unevaluated properties at December 31, 2010 and June 30, 2010, respectively 2,610,049 1,378,222
Other property and equipment 7,494 8,028
Total Property and Equipment 2,617,543 1,386,250
Other Assets    
Derivative financial instruments 14,610
Debt issuance costs, net of accumulated amortization and other assets 45,641 19,637
Total Other Assets 45,641 34,247
Total Assets $2,857,967 $1,566,491
Current Liabilities    
Accounts payable $105,505 $87,103
Accrued liabilities 63,120 68,783
Note payable 6,574
Asset retirement obligations 33,495 35,154
Derivative financial instruments 49,189 1,701
Current maturities of long-term debt 3,008 2,518
Total Current Liabilities 260,891 195,259
Long-term debt, less current maturities, face value of $1,307.9 million and $728.6 million at December 31, 2010 and June 30, 2010, respectively 1,308,337 772,082
Deferred income taxes 2,563 37,215
Asset retirement obligations, net of current portion 310,653 124,123
Derivative financial instruments 45,904 511
Other liabilities 3,689 740
Total Liabilities 1,932,037 1,129,930
Commitments and Contingencies    
Stockholders' Equity    
7.25 % Preferred stock, $0.001 par value, 2,500,000 shares authorized and 99,100 and 1,100,000 shares issued and outstanding at December 31, 2010 and June 30, 2010, respectively. 1 11
5.625 % Preferred stock, $0.001 par value, 2,500,000 shares authorized and 1,150,000 and -0- shares issued and outstanding at December 31, 2010 and June 30, 2010, respectively. 1
Common stock, $0.005 par value, 200,000,000 shares authorized and 74,208,849 and 50,819,109 shares issued and 74,208,196 and 50,636,719 shares outstanding at December 31, 2010 and June 30, 2010, respectively 371 254
Additional paid-in capital 1,471,990 901,457
Accumulated deficit (506,016) (492,867)
Accumulated other comprehensive income (loss), net of income tax expense (benefit) (40,417) 27,706
Total Stockholders' Equity 925,930 436,561
Total Liabilities and Stockholders' Equity $2,857,967 $1,566,491
(In Thousands, except per share information)
  Three Months Ended

December 31,
Six Months Ended

December 31,
  2010 2009 2010 2009
Oil sales $146,539 $98,050 $262,369 $164,343
Natural gas sales 27,414 26,456 55,584 45,070
Total Revenues 173,953 124,506 317,953 209,413
Costs and Expenses        
Lease operating expense 45,247 35,050 89,421 60,475
Production taxes 716 1,007 1,410 2,282
Depreciation, depletion and amortization 62,922 44,972 116,999 80,323
Accretion of asset retirement obligations 6,348 6,160 12,322 11,306
General and administrative expense 15,786 14,022 34,383 22,088
Loss (gain) on derivative financial instruments (1,638) 1,956 (2,776) (4,323)
Total Costs and Expenses 129,381 103,167 251,759 172,151
Operating Income 44,572 21,339 66,194 37,262
Other Income (Expense)        
Bridge loan commitment fees (4,500) (4,500)
Loss on retirement of debt (5,184) (5,184)
Other income 151 27,658 161 29,644
Interest expense (22,094) (24,345) (43,574) (45,307)
Total Other Income (Expense) (31,627) 3,313 (53,097) (15,663)
Income Before Income Taxes 12,945 24,652 13,097 21,599
Income Tax Expense 2,011 8,206 2,030 17,453
Net Income 10,934 16,446 11,067 4,146
Induced Conversion of Preferred Stock 19,796 19,796
Preferred Stock Dividends 2,426 332 4,420 332
Net Income (Loss) Attributable to Common Stockholders $(11,288) $16,114 $(13,149) $3,814
Net Income (Loss) Per Share Attributable to Common Stockholders        
Basic $(0.17) $0.48 $(0.23) $0.12
Diluted $(0.17) $0.46 $(0.23) $0.13
Weighted Average Number of Common Shares Outstanding        
Basic 65,479 33,788 58,241 31,470
Diluted 65,479 35,815 58,241 32,627
(In Thousands)
  Three Months Ended

December 31,
Six Months Ended

December 31,
  2010 2009 2010 2009
Cash Flows From Operating Activities        
Net income $10,934 $16,446 $11,067 $4,146
Adjustments to reconcile net income to net cash provided by (used in) operating activities:        
Depreciation, depletion and amortization 62,922 44,972 116,999 80,323
Deferred income tax expense 2,011 8,206 2,030 17,453
Change in derivative financial instruments        
Proceeds from sale of derivative instruments 8,522 42,577
Other – net (7,515) (4,759) (16,214) (17,115)
Accretion of asset retirement obligations 6,348 6,160 12,322 11,306
Amortization of deferred gain on debt and debt discount and premium (40,383) (29,024) (43,132) (30,867)
Amortization and write-off of debt issuance costs 2,492 3,341 4,254 4,459
Stock-based compensation 391 839 2,180 1,742
Payment of interest in-kind 2,225 2,225
Changes in operating assets and liabilities        
Accounts receivable (48,371) (53,661) (39,971) (38,385)
Prepaid expenses and other current assets 9,883 (14,489) (2,278) (21,185)
Settlement of asset retirement obligations (29,311) (32,615) (34,618) (42,449)
Accounts payable and accrued liabilities 19,354 (10,389) 20,012 (7,149)
Net Cash Provided by (Used in) Operating Activities (498) (64,973) 77,453 (37,721)
Cash Flows from Investing Activities        
Acquisitions (1,013,003) (274,518) (1,013,011) (274,518)
Capital expenditures (65,090) (37,670) (128,625) (47,811)
Insurance payments received 45,199 53,178
Transfer to restricted cash (1,634) (2,160)
Proceeds from the sale of properties 400
Other 115 46 83 134
Net Cash Used in Investing Activities (1,077,978) (268,577) (1,141,153) (271,177)
Cash Flows from Financing Activities        
Proceeds from the issuance of common and preferred stock, net of offering costs 555,773 294,527 560,903 294,527
Conversion of preferred stock to common (11,912) (11,912)
Dividends to shareholders (179) (2,173)
Proceeds from long-term debt 1,113,000 75,837 1,160,000 75,837
Payments on long-term debt (520,838) (118,782) (586,767) (123,443)
Payments for debt issuance costs and other (30,260) (2,063) (30,584) (3,678)
Net Cash Provided by Financing Activities 1,105,584 249,519 1,089,467 243,243
Net Increase (Decrease) in Cash and Cash Equivalents 27,108 (84,031) 25,767 (65,655)
Cash and Cash Equivalents, beginning of period 12,883 107,301 14,224 88,925
Cash and Cash Equivalents, end of period $39,991 $23,270 $39,991 $23,270


  Quarter Ended
  Dec. 31,

Sept. 30,

June 30,

Mar. 31,

Dec. 31,

Operating revenues          
Crude oil sales $156,273 $118,263 $113,908 $117,932 $93,974
Natural gas sales 18,301 19,446 19,945 22,872 16,812
Hedge gain (621) 6,291 5,538 9,323 13,720
Total revenues 173,953 144,000 139,391 150,127 124,506
Percent of operating revenues from crude oil          
Prior to hedge gain 89.5% 85.9% 85.1% 83.8% 84.8%
Including hedge gain 84.2% 80.4% 78.6% 76.0% 78.8%
Operating expenses          
Lease operating expense          
Insurance expense 6,498 6,143 7,220 6,602 7,827
Workover and maintenance 4,105 7,618 5,269 8,452 2,678
Direct lease operating expense 34,644 30,413 28,816 25,778 24,545
Total lease operating expense 45,247 44,174 41,305 40,832 35,050
Production taxes 716 694 1,065 870 1,007
DD&A 62,922 54,077 50,556 50,761 44,972
General and administrative 15,786 18,597 13,127 14,452 14,022
Other – net 4,710 4,836 5,116 6,649 8,116
Total operating expenses 129,381 122,378 111,169 113,564 103,167
Operating income $44,572 $21,622 $28,222 $35,563 $21,339
Sales volumes per day          
Natural gas (MMcf) 53.7 48.1 48.2 48.4 40.7
Crude oil (MBbls) 20.4 17.9 17.3 17.3 14.2
Total (MBOE) 29.4 25.9 25.3 25.4 20.9
Percent of sales volumes from crude oil 69.5% 69.1% 68.3% 68.3% 67.6%
Average sales price          
Natural gas per Mcf $3.70 $4.39 $4.55 $5.25 $4.49
Hedge gain per Mcf 1.85 1.97 2.27 3.03 2.58
Total natural gas per Mcf $5.55 $6.36 $6.82 $8.28 $7.07
Crude oil per Bbl $83.14 $71.79 $72.42 $75.54 $72.17
Hedge gain (loss) per Bbl (5.18) (1.48) (2.80) (2.46) 3.13
Total crude oil per Bbl $77.96 $70.31 $69.62 $73.08 $75.30
Total hedge gain per BOE $(0.23) $2.64 $2.40 $4.08 $7.12
Operating revenues per BOE $64.34 $60.37 $60.50 $65.65 $64.65
Operating expenses per BOE          
Lease operating expense          
Insurance expense 2.40 2.58 3.13 2.89 4.06
Workover and maintenance 1.52 3.19 2.29 3.70 1.39
Direct lease operating expense 12.81 12.75 12.51 11.27 12.74
Total lease operating expense 16.73 18.52 17.93 17.86 18.19
Production taxes 0.26 0.29 0.46 0.38 0.52
DD&A 23.27 22.67 21.94 22.20 23.35
General and administrative 5.84 7.80 5.70 6.32 7.28
Other – net 1.74 2.02 2.22 2.91 4.22
Total operating expenses 47.84 51.30 48.25 49.67 53.56
Operating income per BOE $16.50 $9.07 $12.25 $15.98 $11.09


Barrel – unit of measure for oil and petroleum products, equivalent to 42 U.S. gallons.

Bcfe – billion cubic feet equivalent, used to equate liquid barrels to natural gas volumes at a general conversion rate of 6,000 cubic feet of gas per barrel.

BOE – barrels of oil equivalent, used to equate natural gas volumes to liquid barrels at a general conversion rate of 6,000 cubic feet of gas per barrel.

BOE/d – barrels of oil equivalent per day.

Field – an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

MBOE – thousand barrels of oil equivalent.

MMBOE – million barrels of oil equivalent.

MD – measured depth.

Net Pay – cumulative hydrocarbon-bearing formations.

Net Revenue Interest – the percentage of production revenue allocated to the working interest after first deducting proceeds allocated to royalty and overriding interest.

Spud – to begin drilling a well.

TD – target total depth of a well.

TD'd – to finish drilling a well.

TVD – total vertical depth.

Working Interest – the interest held in lands by virtue of a lease, operating agreement, fee title or otherwise, under which the owner of the interest is vested with the right to explore for, develop, produce and own oil, gas or other minerals and bears the proportional cost of such operations.

Workover / Recompletion – operations on a producing well to restore or increase production. A workover or recompletion may be performed to stimulate the well, remove sand or wax from the wellbore, to mechanically repair the well, or for other reasons.

         Stewart Lawrence
         Vice President, Investor Relations and Communications
         Seymour Pierce - UK AIM Adviser
         Jonathan Wright/
         Jeremy Porter - Corporate Finance
         Richard Redmayne - Corporate Broking
         Tel: +44 (0) 20 7107 8000
         Pelham Bell Pottinger
         James Henderson
         Mark Antelme
         +44 (0) 20 7861 3232

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