Market Overview

Energy XXI Gulf Coast Announces Fourth Quarter and Full Year 2017 Financial and Operational Results

Share:

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,

View Comments and Join the Discussion!
 
Don't Miss Any Updates!
News Directly in Your Inbox
Subscribe to:
Benzinga Premarket Activity
Get pre-market outlook, mid-day update and after-market roundup emails in your inbox.
Market in 5 Minutes
Everything you need to know about the market - quick & easy.
Daily Analyst Rating
A summary of each day’s top rating changes from sell-side analysts on the street.
Fintech Focus
A daily collection of all things fintech, interesting developments and market updates.
Thank You

Thank you for subscribing! If you have any questions feel free to call us at 1-877-440-ZING or email us at vipaccounts@benzinga.com