HOUSTON, March 16, 2018 (GLOBE NEWSWIRE) -- Energy XXI Gulf Coast, Inc. ("EGC" or the "Company") (NASDAQ:EXXI) today reported financial and operational results for the fourth quarter and full year 2017, as well as a change to its Nasdaq ticker symbol.
Highlights and Recent Key Items:
- Produced an average of approximately 27,600 barrels of oil equivalent ("BOE") per day (77% oil) during the fourth quarter, within the Company's guidance range
- Benefited from strong oil price realizations during the fourth quarter of $59.27 per barrel (before the impact of derivatives), approximately 7% higher than the WTI average price of $55.40 per barrel for the quarter
- Incurred a net loss of $215.1 million which included a non-cash ceiling test impairment charge of $145.1 million and a loss on financial derivatives of $33.3 million
- Reported cash and cash equivalents of $152 million at December 31, 2017
- Announced expected total 2018 capital expenditures to be in the range of $145 to $175 million, with $65 to $75 million planned for drilling new wells and recompletes, $10 to $15 million in planned facilities improvements and $50 to $60 million in anticipated plugging and abandonment expenditures
- 2018 drilling program anticipates drilling six wells focused in EGC's core areas in West Delta and South Timbalier, which includes three development wells, one injection well, and two exploitation locations
- Plans to spud the first development well of the 2018 drilling program, the West Delta 73 C-27 McCloud, in March
- Finalized third-party calculation of year-end 2017 proved reserves which totaled 88.2 million barrels of oil equivalent (MMBOE)
- Disclosed that the High Tide well at West Delta 30, as expected, has transitioned to oil and is currently producing approximately 700 barrels of oil and 3.3 million cubic feet of gas per day
- Announced the planned change of its Nasdaq ticker symbol for its common stock from "EXXI" to "EGC" effective March 21, 2018
For the fourth quarter of 2017, EGC reported a net loss of $215.1 million, or $6.47 loss per diluted share. The fourth quarter loss includes a non-cash ceiling test impairment charge of $145.1 million related to the decrease in SEC proved reserves and the PV-10 value of those SEC proved reserves. Financial results were also negatively impacted by lower production and a $33.3 million loss on derivative financial instruments which was partially offset by higher crude prices. In the third quarter of 2017, the Company reported a net loss of $35.2 million, or $1.06 loss per diluted share.
Adjusted EBITDA totaled $10.8 million for the fourth quarter 2017, compared to $35.3 million in the third quarter of 2017. The Company generated $110.5 million in adjusted EBITDA for the full year 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, EGC's Chief Executive Officer and President commented, "2017 was an extremely busy and transitional year for us. As previously announced, after concluding a process to explore potential consolidation transactions, we moved ahead with a stand-alone strategy that includes a 2018 capital budget that should better position EGC for success in 2018 and beyond. We have begun the immediate implementation of that plan with the pending drilling of our first well at West Delta 73."
Mr. Brooks continued, "We have entered 2018 focused on the future with a renewed energy and improved outlook shared by all of us across the Company. We are encouraged by higher oil prices and the significant positive impact they should have on our cash flow and our ability to grow our business again. We anticipate that every dollar increase in oil prices would increase our cash flow by $7 to $9 million that can be deployed in our drilling program, which in 2018 is intended to arrest our production decline. We are excited to have two exploitation wells later in this year's plan that could have a meaningful impact on our reserves and production if successful.
We have rebuilt our management team and remain committed to intense financial discipline throughout our organization and will continue to evaluate our business and align our operational costs with forecasted needs in order to maximize our financial flexibility. We plan to further investigate ways that we can enhance our drilling program and options to fund such a program. We also plan to explore potential divestitures of non-core assets, to be receptive to a future Gulf of Mexico consolidation transaction that creates synergies, and to evaluate and pursue strategic acquisition opportunities in the U.S. Gulf Coast region both offshore and onshore where we can readily deploy our conventional drilling and development expertise. We are optimistic about our future potential and our ability to enhance shareholder value."
To better reflect its corporate identity and strategy as Energy XXI Gulf Coast, Inc., EGC announced today the change of its Nasdaq ticker symbol for its common stock from "EXXI" to "EGC." The common stock will begin trading on Nasdaq under the symbol "EGC" on March 21, 2018. The Company also refreshed its logo and will launch an updated website at www.energyxxi.com on March 21, 2018.
The Company posted an updated investor presentation on its website this morning that includes additional details on the 2018 drilling program, full production and cost guidance for the first quarter of 2018, and full year 2018 along with a year-end reserve analysis. This presentation will be referenced in today's conference call.
Revenue, Production and Pricing
Total revenues for the fourth quarter of 2017 were $93.8 million, which includes a $33.3 million loss on derivative financial instruments, while in the third quarter of 2017, revenues totaled $115.7 million, which included a $12.5 million loss on derivatives.
In the fourth quarter, the Company produced and sold approximately 27,600 net BOE per day, which consists of 21,300 barrels of oil per day ("BOPD") at an average realized price of $59.27 per barrel ("BBL") (before the effect of derivatives), 600 barrels of natural gas liquids ("NGLs") per day at an average realized price of $33.32 per BBL, and 34.5 million cubic feet of gas ("MMCF") per day at an average realized price of $2.97 per thousand cubic feet ("MCF"). During the fourth quarter EGC continued to benefit from the impact of higher realized oil prices (before the effect of derivatives) that were about 7% higher than average WTI prices during the quarter due to the positive differentials that EGC receives on its oil sales.
In the third quarter of 2017, EGC produced and sold approximately 32,600 net BOE per day which consisted of 25,100 BOPD at an average realized price of $49.21 per BBL (before the effect of derivatives), 700 barrels of NGLs per day at an average realized price of $32.15 per BBL, and 40.6 MMCF per day at an average realized price of $3.28 per MCF.
When compared with the third quarter, fourth quarter higher realized prices were offset by natural declines and higher production downtime primarily related to Hurricane Nate and severe winter weather, continued production equipment maintenance, pipeline shut-ins, and facility-related unscheduled downtime. Hurricane Nate and other weather-related issues reduced volumes about 4,000 BOE per day. Production for the full year 2017 averaged approximately 34,200 BOE per day, which also was within guidance ranges.
Costs and Expenses
Total lease operating expenses ("LOE") in the fourth quarter of 2017 was $80.9 million, or $31.90 per BOE, which consisted of $63.9 million in direct lease operating expense, $12.4 million in workover and maintenance and $5.1 million in insurance expense. Total LOE for the third quarter of 2017 was $77.8 million, or $25.92 per BOE. Lease operating expense increased quarter-over-quarter primarily due to weather-related costs and increased maintenance initiatives. EGC remains committed to financial discipline and will continue reviewing costs and expenses but the impact of weather in the fourth quarter and full year 2017 was meaningful. Total LOE was $319.7 million for full year 2017, or $25.59 per BOE.
Gathering and Transportation expense for the fourth quarter of 2017 was $10.2 million, or $4.02 per BOE. EGC did not receive any additional refunds from the Office of Natural Resources Revenue ("ONRR") during the quarter. Pipeline Facility Fee expense was $10.5 million, or $4.14 per BOE. In the third quarter of 2017, Gathering and Transportation expense was a credit of $2.4 million, or ($0.81) per BOE, which included a net refund of $10.6 million from the Office of Natural Resources Revenue ("ONRR") as part of a multi-year federal royalty refund claim, while Pipeline and Facility Fee expense was $10.5 million, or $3.50 per BOE.
G&A expense in the fourth quarter of 2017 was $14.7 million, or $5.80 per BOE compared to $15.1 million, or $5.01 per BOE, in the third quarter 2017. G&A includes non-cash compensation costs of $2.7 million ($1.06 per BOE) in the fourth quarter compared with $3.0 million ($1.00 per BOE) in the third quarter. G&A expense totaled $72.1 million for the full year 2017, or $5.77 per BOE.
Depreciation, depletion and amortization ("DD&A") expense was $33.4 million, or $13.18 per BOE, compared to $36.2 million, or $12.04 per BOE, in the third quarter of 2017. Full year 2017 expense was $150.2 million, or $12.02 per BOE.
Accretion of asset retirement obligation was $10.0 million during the fourth quarter of 2017, compared to $9.7 million in the third quarter. Full year 2017 expense was $42.8 million.
For the full year 2017, EGC recorded no income tax expense or benefit.
Commodity Hedging
EGC currently has fixed price swap contracts benchmarked to NYMEX-WTI to hedge a total of 8,000 BOPD of production for full year 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 January - June 2018, and 2,500 BOPD fixed price swap contracts benchmarked to ICE-Brent for January to June 2018 with an average fixed price of $56.59. The Company has not entered into any additional hedging contracts to-date in 2018. EGC does not have any hedges in place on natural gas production.
Year-end 2017 Reserves
EGC's proved, 2P and 3P reserves are fully engineered by its independent third-party consultants, Netherland Sewell and Associates, Inc. ("NSAI"). Total SEC proved reserves as of December 31, 2017 totaled 88.2 MMBOE, of which 84% were oil, 2% were NGLs and 14% were natural gas. All of the Company's proved reserves are on the Gulf of Mexico Shelf or U.S. Gulf Coast, and 75% are classified as proved developed reserves. SEC 12-month average NYMEX pricing on December 31, 2017 was $47.79 per BBL and $2.98 per MCF, before differentials.
Proved reserves totaled 109.4 MMBOE as of March 31, 2017, the date of the previous NSAI reserves report. The primary non-commodity price factors contributing to the decline in reserves from March 31 to December 31, 2017 include actual production during the period, increased costs due to the modification of fixed versus variable LOE, reserve write-downs, and revisions of previous estimates. The impact of those factors was partially offset by higher SEC average commodity prices for both crude oil and natural gas.
Proved reserves as of December 31, 2017 based on forward strip commodity pricing as of January 26, 2018 of $58.99 per BBL and $2.95 per MCF, before differentials, were estimated to be 92.1 MMBOE.
The PV-10 value of the Company's SEC proved reserves as of December 31, 2017 was $15.1 million, while the PV-10 value of the proved reserves at December 31,2017 based on forward strip commodity pricing as of January 26, 2018 was estimated at $323.1 million.
Total 2P reserves, which includes both proved and probable reserves, was 161.2 MMBOE as of December 31, 2017 using forward strip pricing on January 26, 2018 and the PV-10 value of those reserves was estimated to be $1,003.0 million. Total 3P reserves, which includes proved, probable and possible reserves, was 206.6 MMBOE as of December 31, 2017. Using forward strip commodity pricing on January 26, 2018, the PV-10 value of those reserves was estimated to be $1,554.8 million. Additional details on EGC's year-end reserves are included in the investor presentation posted to the Company's website.
12/31/17 Reserves Summary
| 2017 SEC Pricing | Oil | NGL | Gas | Oil Eq. | PV10 | ||
| Oil $47.79 Gas $2.98 | MMBO | MMBO | BCF | MMBOE | $MM | ||
| PDP | 48.8 | 0.7 | 39.5 | 56.1 | $ | 312.7 | |
| PDN | 6.2 | 0.6 | 19.4 | 10.1 | 87.8 | ||
| PUD | 19.4 | 0.3 | 14.1 | 22.0 | 164.2 | ||
| P&A | 0.0 | 0.0 | 0.0 | 0.0 | (549.6 | ) | |
| Proved | 74.4 | 1.7 | 73.0 | 88.2 | $ | 15.1 | |
| Probable | 45.8 | 1.8 | 124.6 | 68.4 | 538.2 | ||
| P&A | 0.0 | 0.0 | 0.0 | 0.0 | 61.0 | ||
| Total 2P | 120.2 | 3.5 | 197.6 | 156.6 | $ | 614.3 | |
| Total 3P | 152.4 | 4.4 | 263.8 | 200.7 | $ | 1,118.5 | |
PV-10 Value at 2017 SEC Pricing vs. January 26, 2018 Strip Pricing
| 2017 SEC Pricing (1) | PV10 | 1/26/18 Strip Pricing (2) | PV10 | ||||
| MMBOE | $MM | MMBOE | $MM | ||||
| Proved | 88.2 | $ | 15.1 | 92.1 | $ | 323.1 | |
| Probable | 68.4 | $ | 599.2 | 69.1 | $ | 679.9 | |
| Total 2P | 156.6 | $ | 614.3 | 161.2 | $ | 1,003.0 | |
| Total 3P | 200.7 | $ | 1,118.5 | 206.6 | $ | 1,554.8 | |
| (1) Oil $47.79 Gas $2.98 | (2) Oil $58.99 Gas $2.95 | ||||||
PDP: Proved Developed Producing; PDN: Proved Developed Non-Producing; PUD: Proved Undeveloped; P&A: Plug and Abandon; PRB: Probable; 1P: Total Proved Reserves; 2P: Total Proved and Probable Reserves; 3P: Total Proved, Probable and Possible Reserves)
Operational Update and Capital Expenditure Program
During the fourth quarter, the Company incurred capital costs, excluding acquisitions but including abandonment activities, totaling $26.9 million of which $13.3 million was related to development and recompletion activities in the Company's core properties.
Capital Expenditures for the full year 2017 totaled $115.7 million, of which $52.7 million was spent on abandonment activities. EGC drilled two wells in 2017. The WD30 L-14 ST2 High Tide which was spud in June, as expected, has transitioned to oil and is currently producing approximately 700 barrels of oil and 3.3 MMCF per day. The second well, the West Delta 31 L‑19 ST1 Kingstream was unable to reach total depth and has been temporarily abandoned.
As previously reported, capital expenditures for 2018 are expected to be in the range of $145 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. EGC plans to spud the first well in its 2018 drilling program in March, the West Delta 73 C-27 McCloud, a development well location which will be drilled to an expected total vertical depth of 8,400 feet. EGC has 100% working interest in this well and initial production is anticipated during the second quarter. The Company plans to drill a total of six wells in 2018, all of which are located in the West Delta and South Timbalier areas, which includes three development wells, an injection well, and two exploitation wells planned for the second half of 2018 that could add proved reserves if successful.
Balance Sheet and Liquidity
At December 31, 2017, EGC had approximately $74 million in borrowings and $202.6 million in letters of credit issued under its credit agreement. Liquidity totaled approximately $164.2 million, which consists of cash and cash equivalents totaling $151.7 million and $12.5 million in borrowing capacity available under certain conditions.
Conference Call
As previously announced, the Company will hold a conference call to discuss its fourth quarter and full year financial and operating results today, Friday, March 16, 2018, 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 8389039. 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.
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 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 (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) | |||||||||||
| Successor | |||||||||||
| As of | As of | As of | |||||||||
| December 31, | September 30, | December 31, | |||||||||
| 2017 | 2017 | 2016 | |||||||||
| ASSETS | |||||||||||
| Current Assets | |||||||||||
| Cash and cash equivalents | $ | 151,729 | $ | 173,364 | $ | 165,368 | |||||
| Accounts receivable, net | |||||||||||
| Oil and natural gas sales | 55,598 | 49,983 | 69,744 | ||||||||
| Joint interest billings | 6,336 | 3,249 | 6,029 | ||||||||
| Other | 15,726 | 17,762 | 17,944 | ||||||||
| Prepaid expenses and other current assets | 21,602 | 16,096 | 17,980 | ||||||||
| Restricted cash | 6,392 | 6,378 | 32,337 | ||||||||
| Total Current Assets | 257,383 | 266,832 | 309,402 | ||||||||
| Property and Equipment | |||||||||||
| Oil and natural gas properties, net - full cost method of accounting, including $200.2 million, $219.1 million and $376.1 million of unevaluated properties not being amortized at December 31, 2017, September 30, 2017 and December 31, 2016, respectively | 764,922 | 869,713 | 1,097,471 | ||||||||
| Other property and equipment, net | 10,120 | 13,860 | 20,007 | ||||||||
| Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 775,042 | 883,573 | 1,117,478 | ||||||||
| Other Assets | |||||||||||
| Restricted cash | 25,712 | 25,675 | 25,583 | ||||||||
| Other assets and debt issuance costs, net of accumulated amortization | 18,845 | 26,840 | 28,244 | ||||||||
| Total Other Assets | 44,557 | 52,515 | 53,827 | ||||||||
| Total Assets | $ | 1,076,982 | $ | 1,202,920 | $ | 1,480,707 | |||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||||||
| Current Liabilities | |||||||||||
| Accounts payable | $ | 85,122 | $ | 86,691 | $ | 101,117 | |||||
| Accrued liabilities | 45,494 | 38,652 | 55,675 | ||||||||
| Asset retirement obligations | 51,398 | 64,066 | 56,601 | ||||||||
| Derivative financial instruments | 32,567 | 3,302 | -- | ||||||||
| Current maturities of long-term debt | 21 | 23 | 4,268 | ||||||||
| Total Current Liabilities | 214,602 | 192,734 | 217,661 | ||||||||
| Long-term debt, less current maturities | 73,952 | 73,946 | 74,229 | ||||||||
| Asset retirement obligations | 613,453 | 542,904 | 680,507 | ||||||||
| Derivative financial instruments | -- | 574 | -- | ||||||||
| Other liabilities | 10,783 | 16,248 | 12,595 | ||||||||
| Total Liabilities | 912,790 | 826,406 | 984,992 | ||||||||
| Stockholders' Equity | |||||||||||
| Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding at December 31, 2017, September 30, 2017 and December 31, 2016 | -- | -- | -- | ||||||||
| Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963, 33,221,427 and 33,211,594 shares issued and outstanding at December 31, 2017, September 30, 2017 and December 31, 2016, respectively | 333 | 332 | 332 | ||||||||
| Additional paid-in capital | 911,144 | 908,398 | 901,658 | ||||||||
| Accumulated deficit | (747,285 | ) | (532,216 | ) | (406,275 | ) | |||||
| Total Stockholders' Equity | 164,192 | 376,514 | 495,715 | ||||||||
| Total Liabilities and Stockholders' Equity | $ | 1,076,982 | $ | 1,202,920 | $ | 1,480,707 | |||||
| ENERGY XXI GULF COAST, INC. | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||||
| (In Thousands, except per share information) | |||||||||||||||||
| Successor | Predecessor | ||||||||||||||||
| Three Months | Three Months | Three Months | |||||||||||||||
| Ended | Ended | Year Ended | Ended | ||||||||||||||
| December 31, | September 30, | December 31, | December 31, | ||||||||||||||
| 2017 | 2017 | 2017 | 2016 | ||||||||||||||
| Revenues | |||||||||||||||||
| Oil sales | $ | 115,948 | $ | 113,697 | $ | 481,922 | $ | 132,966 | |||||||||
| Natural gas liquids sales | 1,736 | 2,209 | 8,542 | 1,389 | |||||||||||||
| Natural gas sales | 9,423 | 12,261 | 53,805 | 19,368 | |||||||||||||
| Loss on derivative financial instruments | (33,269 | ) | (12,466 | ) | (32,625 | ) | -- | ||||||||||
| Total Revenues | 93,838 | 115,701 | 511,644 | 153,723 | |||||||||||||
| Costs and Expenses | |||||||||||||||||
| Lease operating | 80,927 | 77,822 | 319,671 | 71,408 | |||||||||||||
| Production taxes | 163 | 471 | 1,355 | 268 | |||||||||||||
| Gathering and transportation | 10,207 | (2,441 | ) | 21,666 | (1,624 | ) | |||||||||||
| Pipeline facility fee | 10,494 | 10,495 | 41,977 | 10,165 | |||||||||||||
| Depreciation, depletion and amortization | 33,439 | 36,131 | 150,151 | 29,061 | |||||||||||||
| Accretion of asset retirement obligations | 9,962 | 9,753 | 42,780 | 19,305 | |||||||||||||
| Impairment of oil and natural gas properties | 145,086 | -- | 185,860 | 223 | |||||||||||||
| General and administrative expense | 14,711 | 15,026 | 72,057 | 12,122 | |||||||||||||
| Reorganization items | 311 | -- | 2,555 | -- | |||||||||||||
| Total Costs and Expenses | 305,300 | 147,257 | 838,072 | 140,928 | |||||||||||||
| Operating (Loss) Income | (211,462 | ) | (31,556 | ) | (326,428 | ) | 12,795 | ||||||||||
| Other Income (Expense) | |||||||||||||||||
| Other income, net | 100 | 52 | 254 | 55 | |||||||||||||
| Interest expense | (3,707 | ) | (3,653 | ) | (14,836 | ) | (7,742 | ) | |||||||||
| Total Other Expense, net | (3,607 | ) | (3,601 | ) | (14,582 | ) | (7,687 | ) | |||||||||
| (Loss) Income Before Reorganization Items and Income Taxes | (215,069 | ) | (35,157 | ) | (341,010 | ) | 5,108 | ||||||||||
| Reorganization items | -- | -- | -- | 2,787,613 | |||||||||||||
| (Loss) Income Before Income Taxes | (215,069 | ) | (35,157 | ) | (341,010 | ) | 2,792,721 | ||||||||||
| Income Tax Expense | -- | -- | -- | -- | |||||||||||||
| Net (Loss) Income | $ | (215,069 | ) | $ | (35,157 | ) | $ | (341,010 | ) | $ | 2,792,721 | ||||||
| (Loss) Earnings per Share | |||||||||||||||||
| Basic | $ | (6.47 | ) | $ | (1.06 | ) | $ | (10.26 | ) | $ | 28.25 | ||||||
| Diluted | $ | (6.47 | ) | $ | (1.06 | ) | $ | (10.26 | ) | $ | 26.65 | ||||||
| Weighted Average Number of Common Shares Outstanding | |||||||||||||||||
| Basic | 33,245 | 33,241 | 33,239 | 98,850 | |||||||||||||
| Diluted | 33,245 | 33,241 | 33,239 | 104,787 | |||||||||||||
| ENERGY XXI GULF COAST, INC. | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||||
| (In Thousands) | |||||||||||||||||
| Successor | Predecessor | ||||||||||||||||
| Three Months | Three Months | Year Ended | Three Months | ||||||||||||||
| Ended | Ended | Ended | Ended | ||||||||||||||
| December 31, | September 30, | December 31, | December 31, | ||||||||||||||
| 2017 | 2017 | 2017 | 2016 | ||||||||||||||
| Cash Flows From Operating Activities | |||||||||||||||||
| Net (loss) income | $ | (215,069 | ) | $ | (35,157 | ) | $ | (341,010 | ) | $ | 2,792,721 | ||||||
| Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities: | |||||||||||||||||
| Depreciation, depletion and amortization | 33,439 | 36,131 | 150,151 | 29,061 | |||||||||||||
| Impairment of oil and natural gas properties | 145,086 | -- | 185,860 | 223 | |||||||||||||
| Change in fair value of derivative financial instruments | 28,691 | 14,346 | 32,567 | -- | |||||||||||||
| Accretion of asset retirement obligations | 9,962 | 9,753 | 42,780 | 19,305 | |||||||||||||
| Reorganization items | -- | -- | -- | (2,845,548 | ) | ||||||||||||
| Amortization and write-off of debt issuance costs and other | 6 | 5 | 17 | 4,149 | |||||||||||||
| Deferred rent | 1,930 | 1,930 | 7,891 | 1,670 | |||||||||||||
| Provision for loss on accounts receivable | 300 | -- | 600 | -- | |||||||||||||
| Stock-based compensation | 2,745 | 3,019 | 9,486 | 74 | |||||||||||||
| Changes in operating assets and liabilities | |||||||||||||||||
| Accounts receivable | (4,720 | ) | (5,410 | ) | 17,274 | (23,215 | ) | ||||||||||
| Prepaid expenses and other assets | (6,636 | ) | 669 | 5,167 | 18 | ||||||||||||
| Change in restricted cash | (51 | ) | (51 | ) | 25,817 | (25,157 | ) | ||||||||||
| Settlement of asset retirement obligations | (16,036 | ) | (12,293 | ) | (55,820 | ) | (1,899 | ) | |||||||||
| Accounts payable and accrued liabilities | 12,127 | 3,470 | (35,142 | ) | 10,974 | ||||||||||||
| Net Cash (Used in) Provided by Operating Activities | (8,226 | ) | 16,412 | 45,638 | (37,624 | ) | |||||||||||
| Cash Flows from Investing Activities | |||||||||||||||||
| Capital expenditures | (16,196 | ) | (18,531 | ) | (59,223 | ) | (12,555 | ) | |||||||||
| Insurance payments received | -- | -- | 41 | -- | |||||||||||||
| Change in equity method investments | -- | -- | -- | 31,748 | |||||||||||||
| Change in restricted cash | -- | -- | -- | 48 | |||||||||||||
| Proceeds from the sale of properties | 2,793 | 47 | 4,119 | -- | |||||||||||||
| Other | -- | -- | -- | 124 | |||||||||||||
| Net Cash (Used in) Provided by Investing Activities | (13,403 | ) | (18,484 | ) | (55,063 | ) | 19,365 | ||||||||||
| Cash Flows from Financing Activities | |||||||||||||||||
| Payments on long-term debt | (6 | ) | (3,419 | ) | (4,153 | ) | -- | ||||||||||
| Fees related to debt extinguishment | -- | -- | -- | (32,088 | ) | ||||||||||||
| Debt issuance costs | -- | -- | (61 | ) | 37 | ||||||||||||
| Other | -- | -- | -- | (35 | ) | ||||||||||||
| Net Cash Used in Financing Activities | (6 | ) | (3,419 | ) | (4,214 | ) | (32,086 | ) | |||||||||
| Net Decrease in Cash and Cash Equivalents | (21,635 | ) | (5,491 | ) | (13,639 | ) | (50,345 | ) | |||||||||
| Cash and Cash Equivalents, beginning of period | 173,364 | 178,855 | 165,368 | 215,713 | |||||||||||||
| Cash and Cash Equivalents, end of period | $ | 151,729 | $ | 173,364 | $ | 151,729 | $ | 165,368 | |||||||||
| ENERGY XXI GULF COAST, INC. | |||||||||||
| RECONCILIATION OF NON-GAAP MEASURES | |||||||||||
| (In Thousands, except per share information) | |||||||||||
| (Unaudited) | |||||||||||
| 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 | |||||||||||
| Successor | |||||||||||
| Three Months | Three Months | ||||||||||
| Ended | Ended | Year Ended | |||||||||
| December 31, | September 30, | December 31, | |||||||||
| 2017 | 2017 | 2017 | |||||||||
| Net loss | $ | (215,069 | ) | $ | (35,157 | ) | $ | (341,010 | ) | ||
| Interest expense | 3,707 | 3,653 | 14,836 | ||||||||
| Depreciation, depletion and amortization | 33,439 | 36,131 | 150,151 | ||||||||
| Accretion of asset retirement obligations | 9,962 | 9,753 | 42,780 | ||||||||
| Impairment of oil and natural gas properties | 145,086 | -- | 185,860 | ||||||||
| Change in fair value of derivative financial instruments | 28,691 | 14,346 | 32,567 | ||||||||
| Non-cash stock-based compensation | 2,745 | 3,019 | 9,486 | ||||||||
| Deferred rent(1) | 1,930 | 1,930 | 7,891 | ||||||||
| Severance costs | 325 | 458 | 7,904 | ||||||||
| Adjusted EBITDA | $ | 10,816 | $ | 34,133 | $ | 110,465 | |||||
1) The deferred rent of approximately $1.9 million, $1.9 million and $7.9 million for the three months ended December 31, 2017, three months ended September 30, 2017 and the year ended December 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 | |||||||||||||||||
| | |||||||||||||||||
| Successor | Predecessor | ||||||||||||||||
| Quarter Ended | Year Ended | Quarter Ended | |||||||||||||||
| December 31, | September 30, | December 31, | December 31, | ||||||||||||||
| Operating Highlights | 2017 | 2017 | 2017 | 2016 | |||||||||||||
| (In thousands, except per unit amounts) | |||||||||||||||||
| Operating revenues | |||||||||||||||||
| Oil sales | $ | 115,948 | $ | 113,697 | $ | 481,922 | $ | 132,966 | |||||||||
| Natural gas liquids sales | 1,736 | 2,209 | 8,542 | 1,389 | |||||||||||||
| Natural gas sales | 9,423 | 12,261 | 53,805 | 19,368 | |||||||||||||
| Loss on derivative financial instruments | (33,269 | ) | (12,466 | ) | (32,625 | ) | -- | ||||||||||
| Total revenues | 93,838 | 115,701 | 511,644 | 153,723 | |||||||||||||
| Percentage of operating revenues from crude oil | |||||||||||||||||
| prior to loss on derivative financial instruments | 91% | 89% | 89% | 86% | |||||||||||||
| Operating expenses | |||||||||||||||||
| Lease operating expense | |||||||||||||||||
| Insurance expense | 5,121 | 5,040 | 23,512 | 6,287 | |||||||||||||
| Workover and maintenance | 12,362 | 8,490 | 44,227 | 11,252 | |||||||||||||
| Direct lease operating expense | 63,444 | 64,292 | 251,932 | 53,869 | |||||||||||||
| Total lease operating expense | 80,927 | 77,822 | 319,671 | 71,408 | |||||||||||||
| Production taxes | 163 | 471 | 1,355 | 268 | |||||||||||||
| Gathering and transportation | 10,207 | (2,441 | ) | 21,666 | (1,624 | ) | |||||||||||
| Pipeline facility fee | 10,494 | 10,495 | 41,977 | 10,165 | |||||||||||||
| Depreciation, depletion and amortization | 33,439 | 36,131 | 150,151 | 29,061 | |||||||||||||
| Accretion of asset retirement obligations | 9,962 | 9,753 | 42,780 | 19,305 | |||||||||||||
| Impairment of oil and natural gas properties | 145,086 | -- | 185,860 | 223 | |||||||||||||
| General and administrative | 14,711 | 15,026 | 72,057 | 12,122 | |||||||||||||
| Reorganization items | 311 | -- | 2,555 | -- | |||||||||||||
| Total operating expenses | 305,300 | 147,257 | 838,072 | 140,928 | |||||||||||||
| Operating (loss) income | $ | (211,462 | ) | $ | (31,556 | ) | $ | (326,428 | ) | $ | 12,795 | ||||||
| Sales volumes per day | |||||||||||||||||
| Oil (MBbls) | 21.3 | 25.1 | 25.5 | 29.6 | |||||||||||||
| Natural gas liquids (MBbls) | 0.6 | 0.7 | 0.8 | 0.5 | |||||||||||||
| Natural gas (MMcf) | 34.5 | 40.6 | 47.3 | 73.8 | |||||||||||||
| Total (MBOE) | 27.6 | 32.6 | 34.2 | 42.5 | |||||||||||||
| Percent of sales volumes from crude oil | 77% | 77% | 75% | 70% | |||||||||||||
| Average sales price | |||||||||||||||||
| Oil per Bbl | $ | 59.27 | $ | 49.21 | $ | 51.69 | $ | 48.78 | |||||||||
| Natural gas liquid per Bbl | 33.28 | 32.15 | 29.62 | 28.50 | |||||||||||||
| Natural gas per Mcf | 2.97 | 3.28 | 3.11 | 2.85 | |||||||||||||
| Loss on derivative financial instruments per BOE | (13.12 | ) | (4.15 | ) | (2.61 | ) | -- | ||||||||||
| Total revenues per BOE | 36.99 | 38.54 | 40.95 | 39.36 | |||||||||||||
| Operating expenses per BOE | |||||||||||||||||
| Lease operating expense | |||||||||||||||||
| Insurance expense | 2.02 | 1.68 | 1.88 | 1.61 | |||||||||||||
| Workover and maintenance | 4.87 | 2.83 | 3.54 | 2.88 | |||||||||||||
| Direct lease operating expense | 25.01 | 21.42 | 20.17 | 13.79 | |||||||||||||
| Total lease operating expense per BOE | 31.90 | 25.93 | 25.59 | 18.28 | |||||||||||||
| Production taxes | 0.06 | 0.16 | 0.11 | 0.07 | |||||||||||||
| Gathering and transportation | 4.02 | (0.81 | ) | 1.73 | (0.42 | ) | |||||||||||
| Pipeline facility fee | 4.14 | 3.50 | 3.36 | 2.60 | |||||||||||||
| Depreciation, depletion and amortization | 13.18 | 12.04 | 12.02 | 7.44 | |||||||||||||
| Accretion of asset retirement obligations | 3.93 | 3.25 | 3.42 | 4.94 | |||||||||||||
| Impairment of oil and natural gas properties | 57.20 | -- | 14.88 | 0.06 | |||||||||||||
| General and administrative | 5.80 | 5.01 | 5.77 | 3.10 | |||||||||||||
| Reorganization items | 0.12 | -- | 0.20 | -- | |||||||||||||
| Total operating expenses per BOE | 120.35 | 49.08 | 67.08 | 36.07 | |||||||||||||
| Operating (loss) income per BOE | $ | (83.36 | ) | $ | (10.54 | ) | $ | (26.13 | ) | $ | 3.29 | ||||||