Energy XXI Gulf Coast — Q3 2017 Earnings Presentation
31 slides from Energy XXI Gulf Coast's earnings presentation, Nov 14, 2017
Slide 1: Third Quarter 2017 Earnings Conference Call
www.energyxxi.com Third Quarter 2017 Earnings Conference Call November 14, 2017
Slide 2: Forward-Looking Statements
Forward-Looking Statements This presentation 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 su
Slide 3: Non-GAAP Measures and Cautionary Language on Hydrocarbon Reserves
Non-GAAP Measures and Cautionary Language on Hydrocarbon Reserves EGC refers “PV-10” as the present value of estimated future net revenues of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues less estimated production costs, abandonment costs and develop
Slide 4: EGC Overview
EGC Overview 4 Attractive Upside Optionality with Continued Recovery in Oil Prices 109.4 MMBOE Proved Reserves 80% Oil, 2% NGL, 18% Gas 71% Proved Developed 90% Operated 155 Blocks with 57 Producing Fields 616 Gross Producing Wells 422,944 Net Developed Acres 96,503 Net Undeveloped Acres 17,000 Squa
Slide 5: Steps in the Right Direction
Steps in the Right Direction 5 Safety and Operational Excellence Experienced Leadership Driving New Culture Commitment to Financial Discipline Recent Strong Results Focus on Maximizing Shareholder Value Strong, proficient executive leadership Douglas E. Brooks - Chief Executive Officer & President S
Slide 6: Third Quarter and Recent Results
Third Quarter and Recent Results 6 Produced ~32,600 BOE per day, of which 77% was oil; tropical weather reduced production ~1,200 BOE per day during the third quarter Completed the West Delta 30 High Tide well and initiated production in September; currently producing 650 BOE per day (primarily gas)
Slide 7: Focused on Operational Excellence
Focused on Operational Excellence HSE steering committee formed to identify actions to improve HSE performance and be a top quartile Company by YE 2018 Completed 3rd party safety cultural assessment Execute improvements in employee engagement and safety initiatives Improve BSEE compliance performanc
Slide 8: Production History
Production History 8 BOED 2017 Focused on Minimizing Base Oil Decline 70% 3Q 17 vs. 2Q 17 declined due to: Disruptions due to: shut ins from tropical weather, production equipment maintenance, incremental pipeline and facility related unscheduled downtime totaling ~1,200 BOEPD Quarter-to-quarter nat
Slide 9: Direct LOE, Insurance and Workovers
Direct LOE, Insurance and Workovers 9 2017 Focused on Sustainable Cost Reduction and Optimization Savings in Multiple Categories Q3 2017 total LOE 9% below Q2 2017 Go forward cost savings initiatives: Sole sourcing items such as labor and chemicals Inventory management, reduction of third party cost
Slide 10: Pipeline Facility Fee and Gathering & Transportation
Pipeline Facility Fee and Gathering & Transportation 10 2017 Focused on ONRR Refunds and Minimizing Costs Includes Gathering and Transportation credits related to ONRR refunds for the following quarters: Q217 ~$5MM, Q317 ~$11MM Midpoint of Q4 2017 guidance (1) Pipeline Facility Fee flat $10.5 MM qua
Slide 11: G&A Expenses
G&A Expenses(2) 11 Q3 2017 costs 27% below Q2 2017 Total headcount reduced 18% in 2Q 2017 EGC expects $8 to $8.5 MM of annualized G&A and LOE savings from reduced staffing YTD 2017 includes $7.6 MM related to severance costs 2017 also includes restructuring, reorganization and bankruptcy emergence c
Slide 12: Margin Analysis $/BOE
Margin Analysis 12 12 $/BOE Cost Controls and Interest Reduction Drives Down Breakeven and Increases Cash Flow in a Rising Commodity Price Environment 1) Q1, Q2 & Q3 2017 excludes non-cash items (1) (1) (1) $19.65 $17.58 $23.57 $26.05 $25.79 $1.33 $3.00 $2.71 $4.09 $2.83 $5.79 $3.10 $5.61 $5.45 $4.0
Slide 13: Liquidity Profile
Liquidity Profile 13 September 30, 2017 $MM Total Cash & Cash Equivalents(1) $173 Exit Credit Agreement $290 Less: Amount Drawn ( $74) Less: Letter of Credit Utilization(2) ($203) Total Available Credit Facility(3) $13 Total Liquidity $186 (1) Does not include restricted cash of $32MM which consists
Slide 14: Crude Hedge Profile
Crude Hedge Profile (As of 11/14/17) Currently Hedged 10,000 bpd of Bal17 $52.30-57.43 LLS Costless Collars 1,500 bpd of Oct17 $51.68 WTI Swaps 3,500 bpd of Nov-Dec17 $51.81 WTI Swaps 8,000 bpd of Cal18 $50.68 WTI Swaps 2,000 bpd of Jan-Jun18 $55.45 LLS Swaps 2,500 bpd of Jan-Jun18 $56.59 Brent Swap
Slide 15: 2017 Capital Budget Update
2017 Capital Budget Update 2017 Capital Program Funded with Internally Generated Cash Flow and Available Cash 15 Estimated Capital: $115 - $130 million Includes abandonment costs of $50 - $65 million Development Drilling Program Successfully drilled first well: WD30 L-14 ST2 High Tide 100% working i
Slide 16: High Tide Development Update
L Kingstream High Tide Development Update High Tide (L-14 ST2) Targeted three horizons All three targets were found at their expected locations and two of the three sands were thicker than expected 102 feet of net pay versus pre-drill estimate of 60 - 90 feet Well completed in September Early result
Slide 17: 2017 Q4 Guidance
2017 Q4 Guidance (As of 11/14/17) 17 Production is priced 60-70% HLS; 30-40% LLS Reflects impact of curtailments due to Hurricane Nate and pipeline repair and maintenance ~4,000 – 5,000 BOEPD Q4 2017 Capex consists of D&C capex ~$3-$6 MM; P&A capex ~$12-$20 MM; Capitalized G&A ~$4 – $7 MM; Facilitie
Slide 18: Overview of Strategic Alternative Process
Overview of Strategic Alternative Process 18 Initiated process with Morgan Stanley in late March Merger or consolidation discussion Stand-Alone Plan Capital infusion Forecasts, portfolio evaluation/optimization Reasonable interest in GOM Shelf consolidation (NDAs signed) Existing GOM public E&Ps and
Slide 19: Overview of Strategic Alternative Process
Overview of Strategic Alternative Process 19 Challenges of consolidation Counterparty balance sheets Offshore recovery lags onshore recovery Challenging public and capital market environment for offshore given current oil price levels No executable combination resulted from the review process All pa
Slide 20: Stand-Alone Path Forward
Stand-Alone Path Forward 20 Multiple development plans considered Base Development Plan (subject to capital constraints, see slide #23) Focus on protecting liquidity, covenants and balance sheet Continued G&A and operating cost reductions Minimize production decline with recompletion program and con
Slide 21: EGC Scenario Assumptions
EGC Scenario Assumptions 21 Strip pricing of approximately $50 WTI for all scenarios Every $1 improvement in oil price increases annual cash flow $7-$9 MM Costs Recent operational focus has identified and is delivering sustainable reductions to lower the inherently high fixed costs of our Shelf asse
Slide 22: EGC Scenario Assumptions
EGC Scenario Assumptions 22 Drilling and Completion Capital Projects have minimum return thresholds of 20% IRR and up to 50%+ IRR Preliminary Base Development Plan includes: 5-8 wells in 2018 ($60 - $90 MM) 6-12 wells in 2019 ($60 - $130 MM)* Preliminary Accelerated Development Plan includes: 8-12 w
Slide 23: Base Development Scenario Outcomes
Production mix 75-85% Oil 2018 exit rate range 28,000 – 32,000 boepd Minimize production decline with recompletion and conservative development drilling program Remain poised for potential future consolidation Drilling and Completion capex 5-8 wells in 2018 and 6-12 wells in 2019 One rig deployed Q2
Slide 24: Accelerated Development Scenario Outcomes
Production mix 75-85% Oil 2018 exit rate range 30,000 – 34,000 boepd Arrests production decline in 2018 and achieves production growth in 2019 Remain poised for potential future consolidation Drilling and completion capex spend 8-12 wells in 2018 and 15-20 wells in 2019 One rig deployed Q1 2018 One
Slide 25: Appendix
Appendix 25
Slide 26: Leading Operator in GOM Shelf
Leading Operator in GOM Shelf 26 EGC Core Properties(1) Field Operator W/I Cum. Prod. (MMBOE) West Delta 73 Energy XXI 100% 389 South Timbalier 54 Energy XXI 100% 152 South Pass 49 Energy XXI 100% 111 Main Pass 61 Energy XXI 100% 65 Ship Shoal 208 Energy XXI 100% 457 West Delta 30 Energy XXI 100% 75
Slide 27: BOEM and BSEE Update
BOEM and BSEE Update 27 Excellent working relationship with BOEM and BSEE Continue to operate under the terms and proposals of our plan with the BOEM EGC has bonded its sole properties and further focused bonding efforts on expired properties and properties without a major oil company in the chain o
Slide 28: SEC Proved Reserves – March 31, 2017
SEC Proved Reserves – March 31, 2017(1) 28 Reserves Category Net Oil Net NGL Net Gas Net Total PV101 MMBO MMBBL BCF MMBOE MM$ Proved Developed Producing 51.8 0.9 53.7 61.6 $304.9 Proved Developed Non-Producing 9.3 0.9 33.2 15.7 $100.8 Proved Undeveloped 26.5 0.5 30.3 32.0 $203.7 Plug and Abandon - -
Slide 29: Strip Proved Reserves – March 31, 2017
Strip Proved Reserves – March 31, 2017(1) 29 Reserves Category Net Oil Net NGL Net Gas Net Total PV101 MMBO MMBBL BCF MMBOE MM$ Proved Developed Producing 53.8 0.9 56.1 64.1 $457.4 Proved Developed Non-Producing 9.7 0.9 34.8 16.4 $133.9 Proved Undeveloped 27.5 0.5 31.1 33.2 $278.4 Plug and Abandon -
Slide 30: Adjusted EBITDA Reconciliation
Adjusted EBITDA Reconciliation 30 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, or US GAAP. EGC believes that Adjusted EBITDA is useful because it allows it t
Slide 31: Investor Relations Contact
[email protected] 713-351-0617 Al Petrie – Investor + Media Relations Coordinator
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