August 10, 2017

Energy XXI Gulf Coast Announces Second Quarter 2017 Financial and Operational Results

Initial Well in 2017 Drilling Program Successful

HOUSTON, Aug. 10, 2017 (GLOBE NEWSWIRE) -- Energy XXI Gulf Coast, Inc. ("EGC" or the "Company") (NASDAQ:EXXI) today reported financial and operational results for the second quarter of 2017. 

Second Quarter 2017 Highlights and Recent Key Items:

  • Grew current cash and cash equivalents to $179 million
  • Produced an average of approximately 36,000 barrels of oil equivalent ("BOE") per day, of which 75% was oil
  • Reduced total headcount in the second quarter of 2017 by approximately 18%; reductions expected to result in $8 million to $8.5 million in annualized cost savings
  • Expanded 2017 commodity hedging program by adding WTI fixed price swap contracts and initiated 2018 commodity hedging program by adding WTI fixed price swap contracts for full year 2018
  • Joined FTSE Russell 3000® Index
  • Successfully drilled the first well in 2017 development program, the West Delta 30 L-14 ST2 High Tide well, with better-than-expected net pay
  • Reduced 2017 capital spending budget to $125 million to $155 million
  • Continued to work with financial advisors on long-term plan and review of strategic alternatives

For the second quarter of 2017, EGC reported a net loss of $23.6 million or $0.71 loss per diluted share.  In the first quarter of 2017, the Company reported a net loss of $65.3 million, or $1.97 loss per diluted share.  Adjusted EBITDA totaled $24.4 million for the second quarter 2017 versus $42.6 million in the first quarter 2017. Second quarter 2017 financial results were reduced primarily due to lower production volumes and lower oil prices; higher production costs were more than offset by lower gathering and transportation and G&A expenses. The first quarter included a non-cash ceiling test impairment charge of $44.1 million while the second quarter reflects a credit to past impairment charges of $0.9 million. The credit pertains to the correction of immaterial errors related to certain asset retirement obligations which impacted the past ceiling test calculations.

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, EGC's Chief Executive Officer and President commented, "In the second quarter we were able to grow our cash position by $18 million, add 2017 hedges at an average oil price of $51.74, and successfully spud our first new well in nearly two years.  The West Delta 30 High Tide well that we operated with a 100% working interest was drilled off an existing platform for less than our initially estimated cost to 8,500 feet total vertical depth and encountered better-than-expected net pay and reservoir characteristics.  We plan to complete the well before the end of the third quarter. We remain confident in our inventory of approximately 40 development drilling locations that are available to us in the future."

Brooks continued, "For the remainder of 2017, we intend to focus on operating safely, efficiently and effectively to deliver predictable and repeatable results. We will accomplish this through enhancing our base production and undertaking low-cost, low-risk projects. We will continue to drive down costs in areas we can control and right size our organization to better align with our future needs. We will opportunistically add hedges to minimize downside risk exposure and maximize cash flow generation from our production, as demonstrated with our expanded hedging program for a portion of our 2018 volumes. We continue to work on our long-term strategic plan, and are evaluating a variety of alternatives with our financial advisors."

Revenue, Production and Pricing
Total revenues for the second quarter of 2017 were $143.7 million, which includes a $9.4 million gain on derivative financial instruments, while in the first quarter, revenues totaled $157.9 million, which included a $3.7 million gain on derivatives.

In the second quarter, the Company produced and sold approximately 36,000 net BOE per day, which was comprised of 26,800 barrels of oil per day ("BOPD") at an average realized price of $48.45 per barrel ("BBL") (before the effect of derivatives), 1,000 barrels of natural gas liquids ("NGL's") per day at an average realized price of $27.37 per BBL, and 48.9 million cubic feet of gas ("MMCF") per day at an average realized price of $3.09 per thousand cubic feet ("MCF").  In the first quarter, EGC produced and sold approximately 41,000 net BOE per day which was comprised of 29,100 BOPD at an average realized price of $51.04 per BBL (before the effect of derivatives), 900 barrels of NGL's per day at an average realized price of $27.52 per BBL, and 65.9 MMCF per day at an average realized price of $3.10 per MCF.  When compared with the first quarter, second quarter production declined primarily due to temporary disruptions associated with shut-ins from Tropical Storm Cindy (~750 BOEPD), as well as incremental third-party non-operated pipeline shut-ins and facility-related unscheduled downtime (~350 BOEPD). The balance of the reductions were related to quarter-to-quarter natural declines.  EGC operates approximately 90% of its reserves, substantially all of which are located in the U.S. Gulf of Mexico.

Second Quarter 2017 Costs and Expenses
Total lease operating expense ("LOE") was $85.3 million, or $26.11 per BOE, which consisted of $64.9 million in direct lease operating expense, $13.4 million in workover and maintenance and $7.1 million in insurance expense. Total LOE for the first quarter of 2017 was $75.2 million, or $20.39 per BOE.  LOE per BOE was driven higher due to lower production volumes and higher LOE costs. Absolute LOE costs were higher during the second quarter primarily due to increased maintenance and workover activity, and higher-than-expected third party non-operated production costs, a portion of which pertained to the first quarter. EGC has successfully completed nearly 350 expense-related workover and maintenance projects during the first half of 2017. 

Gathering and Transportation expense was $13.2 million, or $4.03 per BOE for the second quarter of 2017, which included a $4.7 million Office of Natural Resources Revenue ("ONRR") refund. In the first quarter of 2017, Gathering and Transportation expense was $21.7 million, or $5.89 per BOE and included increased commodity marketing deductions and expenses incurred on pipeline storage facility repairs.

G&A expense in the second quarter of 2017 was $20.7 million, or $6.34 per BOE compared to $21.6 million, or $5.86 per BOE in the first quarter 2017.   The decrease in G&A expense was primarily due to lower employee salary costs.  During the second quarter, total headcount was reduced by 18% to adjust staffing to EGC's current operational plan.  This reduction resulted in severance and separation costs of approximately $2.5 million in the second quarter.  The Company expects to realize a total of approximately $8 million to $8.5 million of annualized G&A and LOE savings from this staff reduction.  G&A includes non-cash compensation costs of $2.9 million ($0.88 per BOE) in the second quarter compared with $0.9 million ($0.24 per BOE) in the first quarter.  

Depreciation, depletion and amortization ("DD&A") expense was $38.7 million, or $11.83 per BOE compared to $42.0 million, or $11.39 per BOE in the first quarter of 2017. 

Accretion of asset retirement obligation was $10 million during the second quarter 2017, compared to $12.4 million in the first quarter of 2017. 

For the first half of 2017, EGC recorded no income tax expense or benefit.

Commodity Hedging 
In May 2017, EGC entered into fixed price swap contracts benchmarked to NYMEX-WTI, to hedge 1,500 BOPD of production for the period from June 2017 to October 2017 and 3,500 barrels of oil per day of production for November 2017 and December 2017 with an average fixed price swap of $51.74. These swaps complement the costless collars previously in place of 10,000 barrels of oil per day for the remainder of 2017, with an average floor price of $52.30 and an average ceiling price of $57.43 per barrel. In August 2017, EGC entered into WTI fixed price swap contracts benchmarked to NYMEX-WTI, to hedge 2,000 BOPD, at an average oil price of $49.52 for full year 2018.  The Company continues to evaluate additional derivative arrangements to help limit the downside risk of adverse price movements.  EGC does not have any hedges in place on natural gas production.

Capital Expenditure Program
The current development plan is focused on the West Delta area where the first well in EGC's 2017 development program, the 30 L-14 ST2 High Tide well was spud on June 7, 2017.  The High Tide well is located in the West Delta 30 field, which ranks as the largest oil field in the Gulf of Mexico Shelf based on cumulative production. The well was drilled to a total vertical depth of 8,500 feet and encountered 102 feet of net pay across three prospective horizons. This well will be completed and placed on production before the end of the third quarter. In July, EGC spud its second development well, the West Delta 31 L-19 ST1 Kingstream. The well encountered an unanticipated fluid loss zone ("thief zone") while drilling and was not able to be drilled beyond the problematic zone.  The temporary abandonment of the well is being finalized and a plan is being evaluated to potentially re-drill the well from a different location to avoid the thief zone and reach the targeted reserves.

During the three months ended June 30, 2017, the Company incurred capital costs, excluding acquisitions but including abandonment activities, totaling $31.8 million.  The Company spent approximately $14.4 million on development of its core properties and $17.4 million related to abandonment activities.

In light of the continued uncertainty of commodity prices and to preserve its strong balance sheet and liquidity, EGC has revised its capital expenditure program for 2017 downward from $140 to $170 million to $125 to $155 million, including $50 to $70 million for abandonment activities. The Company does not plan to drill any additional wells this year beyond those already spud, but will continue to implement its previously-announced workover and recompletion program. EGC expects to fund its 2017 capital program with cash on hand and cash generated from ongoing operations. 

Balance Sheet and Liquidity
The Company's estimate of its asset retirement obligations decreased by $7.8 million during the three months ended June 30, 2017, primarily due to costs expended for plugging and abandonment. Asset retirement obligations totaled $615.2 million at the end of the second quarter 2017.

At June 30, 2017, EGC had approximately $74 million in borrowings and $202.8 million in letters of credit issued under its exit credit agreement. Liquidity totaled $192 million which is comprised of cash and cash equivalents totaling $179 million and $12.5 million in available borrowing capacity under certain conditions outlined in the exit credit agreement. 

Addition to the Russell 3000® Index
The Company was added to the Russell 3000® Index on June 26, 2017. EGC's addition to the Russell 3000® Index should provide greater awareness among institutional investors, while providing additional liquidity in the Company's shares.

Conference Call
As previously announced, the Company will hold a conference call to discuss its second quarter financial and operating results tomorrow, Friday, August 11, 2017, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time). Interested parties may participate by dialing (877) 794-3620.  International parties may dial (631) 813-4724.  The confirmation code is 55683951.  This call will also be webcast on EGC's website at A replay of the call will be archived and available on the web site shortly after the live call.          

Fresh Start Accounting
Upon emergence from the Company's Chapter 11 restructuring, EGC elected to adopt fresh start accounting as of December 30, 2016. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after December 31, 2016 are not comparable with the financial statements prior to that date. References to "Successor" refer to the reorganized EGC subsequent to the adoption of fresh start accounting. References to "Predecessor" refer to Energy XXI Ltd. prior to the adoption of fresh start accounting.

Non-GAAP Measures
Adjusted EBITDA is a supplemental non-GAAP financial.  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 it 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. 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. It is not possible to predict or identify all such factors and the following list should not be considered a complete statement of all potential risks and uncertainties relating to emergence from Chapter 11, the recent change in EGC's senior management team, or EGC's oil and gas reserves, including, but not limited to: (i) the effects of the changes in  EGC's senior leadership on the Company's employees, suppliers, regulators and business counterparties, (ii) the impact of restrictions in the exit financing on EGC's ability to make capital investments and pursue strategic growth opportunities and (iii) 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 Part I, Item 1A, "Risk Factors" of the Transition Report on Form 10-K for the transition period ended December 31, 2016 filed by EGC for more information.  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. is an independent oil and natural gas development and production company whose assets are primarily located in the U.S. Gulf of Mexico waters offshore Louisiana and Texas.  The Company's near-term strategy emphasizes exploitation of key assets, enhanced by its focus on financial discipline and operational excellence. To learn more, visit EGC's website at

 (In Thousands, except share information)
  June 30,    March 31,
   December 31,
  2017 2017
ASSETS (Unaudited)  (Unaudited)
Current Assets       
Cash and cash equivalents $178,855 $160,479 $165,368
Accounts receivable       
Oil and natural gas sales  52,691  67,952  68,143
Joint interest billings, net  2,498  5,687  5,600
Other  8,318  2,321  17,944
Prepaid expenses and other current assets  17,176  21,449   25,957
Restricted cash  6,365  7,114  32,337
Derivative financial instruments  10,470  3,409  -
Total Current Assets  276,373  268,411  315,349
Property and Equipment       
Oil and natural gas properties, net - full cost method of accounting, including
$224.5 million$283.9 million and $376.1 million of unevaluated properties not
being amortized at June 30, 2017, March 31, 2017 and December 31, 2016, respectively
  869,398  893,360  1,097,479
Other property and equipment, net  15,107  16,277  18,807
Total Property and Equipment, net of accumulated depreciation, depletion, amortization
and impairment
  884,505  909,637  1,116,286
Other Assets       
Restricted cash  25,637  25,606  25,583
Other assets  27,011  25,681  28,244
Total Other Assets  52,648  51,287  53,827
Total Assets $1,213,526 $1,229,335 $1,485,462
Current Liabilities       
Accounts payable $80,891 $70,706 $101,117
Accrued liabilities  34,517  33,827  63,660
Asset retirement obligations  61,766  73,073  56,601
Current maturities of long-term debt  3,443  3,616  4,268
Total Current Liabilities  180,617   181,222  225,646
Long-term debt, less current maturities  73,940  73,996  74,229
Asset retirement obligations  553,515  549,938  696,763
Other liabilities  16,347  14,299  14,481
Total Liabilities  824,419  819,455  1,011,119
Commitments and Contingencies       
Stockholders' Equity         
Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding
at June 30, 2017, March 31, 2017 and December 31, 2016
  -  -  -
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,221,427, 33,211,594
and 33,211,594 shares
issued and outstanding at June 30, 2017, March 31, 2017 and December 31, 2016 respectively  332  332  332
Additional paid-in capital  884,008  881,138  880,286
Accumulated deficit  (495,233)  (471,590)  (406,275)
Total Stockholders' Equity  389,107  409,880  474,343
Total Liabilities and Stockholders' Equity $1,213,526 $1,229,335 $1,485,462

(In Thousands, except per share information)
 Successor   Predecessor
 Three Months
       Three Months
     Three Months
 June 30,
 March 31,
   June 30,
Oil sales$118,180 $133,621   $130,083
Natural gas liquids sales 2,370  2,227  2,996
Natural gas sales 13,753  18,368  14,725
Gain on derivative financial instruments 9,412  3,698  -
Total Revenues 143,715  157,914   147,804
Costs and Expenses        
Lease operating 85,336  75,157  76,803
Production taxes 482  239  155
Gathering and transportation 13,172  21,716  14,260
Depreciation, depletion and amortization 38,661  42,006  40,078
Accretion of asset retirement obligations 10,050  12,397  18,905
Impairment of oil and natural gas properties (848)  44,054  142,640
General and administrative expense 20,716  21,604  23,174
Reorganization items (3,773)  2,244  -
Total Costs and Expenses 163,796  219,417  316,015
Operating Loss (20,081)  (61,503)  (168,211)
Other Income (Expense)        
Other income, net 80  22  160
Interest expense (3,642)  (3,834)  (13,438)
Total Other Expense, net (3,562)  (3,812)  (13,278)
Loss Before Reorganization Items and Income Taxes (23,643)  (65,315)  (181,489)
Reorganization items -  -  (14,201)
Loss Before Income Taxes (23,643)  (65,315)  (195,690)
Income Tax Benefit -  -  (138)
Net Loss (23,643)  (65,315)  (195,552)
Preferred Stock Dividends -  -  352
Net Loss Attributable to Common Stockholders$(23,643) $(65,315) $(195,904)
Loss per Share        
Basic and Diluted$(0.71) $(1.97) $(2.01)
Weighted Average Number of Common Shares Outstanding                                                            
Basic and Diluted 33,237  33,228  97,540

(In Thousands)
      Three Months
 Three Months
Three Months
      June 30 ,
 March 31,
June 30,
Cash Flows From Operating Activities            
Net loss     $(23,643) $(65,315)$(195,55)
Adjustments to reconcile net loss to net cash provided by             
operating activities:            
Depreciation, depletion and amortization      38,661  42,006 40,078
Impairment of oil and natural gas properties       (848)  44,054 142,640
Change in fair value of derivative financial instruments      (7,061)  (3,409)  -
Accretion of asset retirement obligations      10,050  12,397 18,905
Amortization and write off of debt issuance costs and other      6   - 881
Deferred rent      2,016  2,015 2,215
Provision for loss on accounts receivable      300  - 3,200
Reorganization items      (3,773)  - -
Stock-based compensation      2,870  852 163
Changes in operating assets and liabilities            
Accounts receivable      12,153  15,727 9,145
Prepaid expenses and other assets      4,165  6,969 (11,519)
Restricted cash      718  25,201  
Settlement of asset retirement obligations      (18,175)  (9,316) (3,241)
Accounts payable, accrued liabilities and other      8,515  (59,683) 25,332
Net Cash Provided by Operating Activities      25,954  11,498 32,247
Cash Flows from Investing Activities            
Capital expenditures      (5,391)  (19,105) (18,053)
Insurance payments received      (2,010)  2,051 3,872
Transfer to restricted cash      -  - 756
Proceeds from the sale of other property and equipment      10  1,269 1,070
Other      -  - (81)
Net Cash Used in Investing Activities      (7,391)  (15,785)  (12,436)
Cash Flows from Financing Activities            
Payments on long-term debt      (126)  (602) -
Debt issuance costs      (61)  - -
Net Cash Used in Financing Activities      (187)  (602) -
Net Increase (Decrease) in Cash and Cash Equivalents       18,376  (4,889) 19,811
Cash and Cash Equivalents, beginning of period      160,479  165,368 183,447
Cash and Cash Equivalents, end of period     $178,855 $160,479$203,258


(In Thousands, except per share information)
As required under Regulation G of the Securities Exchange Act of 1934, provided below is a reconciliation of net loss to Adjusted EBITDA, a non-GAAP      
financial measure.
  Three Months    Three Months
   Ended  Ended
  June 30,  March 31,
  2017  2017
Net Loss$(23,643) $(65,315)
Interest expense 3,642  3,834
Depreciation, depletion and amortization 38,661  42,006
Impairment of oil and natural gas properties (848)  44,054
Accretion of asset retirement obligations 10,050  12,397
Change in fair value of derivative financial instruments (7,061)  (3,409)
Non-cash stock-based compensation 2,870  852
Deferred rent (1) 2,016  2,015
Reorganization items (3,773)  2,244
Severance costs 2,500  3,956
Adjusted EBITDA$24,414 $42,634

(1) The deferred rent of approximately $2 million for the three months ended June 30 and March 31, 2017, 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
     Quarter Ended    
        June 30,
   March 31,
June 30,
Operating Highlights       2017   2017
Operating revenues             
Oil sales       $118,180     $133,621$ 130,083
Natural gas liquids sales        2,370   2,227 2,996
Natural gas sales        13,753  18,368 14,725
Gain on derivative financial instruments        9,412  3,698 -
Total revenues         143,715  157,914 147,804
Percentage of oil revenues prior to gain             
on derivative financial instruments        88%  87% 88%
Operating expenses             
Lease operating expense             
Insurance expense        7,101  6,250 8,269
Workover and maintenance        13,370  10,005 17,471
Direct lease operating expense        64,865  58,902 51,063
Total lease operating expense        85,336  75,157 76,803
Production taxes        482   239 155
Gathering and transportation        13,172  21,716 14,260
Depreciation, depletion and amortization        38,661  42,006 40,078
Accretion of asset retirement obligations        10,050  12,397 18,905
Impairment of oil and natural gas properties         (3,421)  44,054 142,640
General and administrative        20,716  21,604 23,174
Reorganization items        (3,773)  2,244 -
Total operating expenses        163,796   219,417 316,015
Operating loss       $(20,081) $(61,503)$(168,211)
Sales volumes per day             
Oil (MBbls)        26.8  29.1 31.4
Natural gas liquids (MBbls)        1.0  0.9 1.5
Natural gas (MMcf)        48.9  65.9 86.5
Total (MBOE)        35.9  41.0 47.3
Percent of sales volumes from oil        75%  71% 66%
Average sales price             
Oil per Bbl        $48.45 $51.04$45.55
Natural gas liquid per Bbl        27.37  27.52 21.55
Natural gas per Mcf        3.09  3.10 1.87
Gain on derivative financial instruments per Bbl         2.88  1.00 -
Total revenues per BOE        43.99  42.83 34.32
Operating expenses per BOE             
Lease operating expense             
Insurance expense         2.17  1.70 1.92
Workover and maintenance        4.09  2.71 4.06
Direct lease operating expense        19.85  15.98 11.86
Total lease operating expense per BOE        26.11  20.39 17.84
Production taxes        0.15  0.06 0.04
Gathering and transportation        4.03  5.89 3.31
Depreciation, depletion and amortization        11.83  11.39 9.31
Accretion of asset retirement obligations        3.08  3.36 4.39
Impairment of oil and natural gas properties        (0.26)  11.95 33.12
General and administrative        6.34  5.86 5.38
Reorganization items        (1.15)  0.61 -
Total operating expenses per BOE        50.13  59.51 73.39
Operating loss per BOE       $(6.14) $(16.68)$(39.07)


Investor Relations Contact

Al Petrie

Investor Relations Coordinator


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Source: Energy XXI

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