JP Morgan Energy Conference Dane Whitehead

Transcription

1 JP Morgan Energy Conference Dane Whitehead Chief Financial Officer June 2, 218

2 Forward-Looking Statements and Other Matters This presentation (and oral statements made regarding the subjects of this presentation) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including, without limitation: the Company's future performance, business strategy, asset quality, production guidance, drilling plans, 218 capital plans, cost and expense estimates, cash flows, uses of excess cash, returns, including CROIC and CFPDAS, and E.G. EBITDAX, cash margins, asset sales and acquisitions, leasing and exploration activities, future financial position, tax rates and other plans and objectives for future operations. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," may, "plan," "project," "seek," should, "target," "will," "would," or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While the Company believes its assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those projected, including, without limitation: conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the jurisdictions in which the Company operates, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; capital available for exploration and development; risks related to our hedging activities; well production timing; drilling and operating risks; availability of drilling rigs, materials and labor, including the costs associated therewith; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions; acts of war or terrorism, and the governmental or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company s 217 Annual Report on Form 1-K, Quarterly Reports on Form 1-Q and other public filings and press releases, available at Except as required by law, the Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise. Use of non-gaap financial measures- This presentation includes non-gaap financial measures. The non-gaap financial measures are not alternatives to GAAP measures, and you should not consider these non-gaap financial measures in isolation or as a substitute of our results as reported under GAAP. Reconciliations of the differences between non-gaap financial measures used in this presentation and their most directly comparable GAAP financial measures are available at in the 1Q 218 Investor Packet. 2

3 Overview First Quarter 218 Strong 1Q18 production growth; 218 resource play guidance raised, $2.3B development capital budget unchanged >5% of crude volumes tied to Brent or LLS pricing 65% y/y improvement in CROIC at $65 WTI Strong Eagle Ford and Bakken performance continues to expand the core Captured a largely contiguous position in emerging Louisiana Austin Chalk play at <$9 / acre Recent Highlights Bakken s Hector performance continues to impress; Olea Three Forks well reports IP24 rate of 7,877 BOED Signed agreement to divest the Atrush block in Kurdistan for $6MM Signed HOA with the EG government and NBL to process gas from NBL s Alen field through EGLNG 3

4 Rate of Change on Corporate Performance Metrics Resource play growth raised in Q1 with $2.3B budget unchanged 218 vs 217 Metrics At $5 WTI At $6 WTI At $65 WTI CROIC 1 improvement: 3% 5% 65% CFPDAS 2 improvement: 1% 3% 45% Total production Boe growth: 1-14% Oil growth: 16-2% Resource play production (Oil & BOE) 25-3% 1 CROIC = Cash return on invested capital; calculated by taking cash flow (Operating Cash Flow before working capital + net interest after tax) divided by (average 4 Stockholder s Equity + average Net Debt) 2 CFPDAS = Cash flow per debt adjusted share; calculated by taking cash flow (Operating Cash Flow before working capital + net interest after tax) divided by total shares including debt shares. Debt shares is the average net debt during a calendar year divided by the average annual stock price. Metrics exclude Libya in 218. See the 4Q 217 Investor Packet at for non-gaap reconciliations

5 Differentiated Position in Top 4 U.S. Basins Diversified portfolio provides operational flexibility Appraise / Delineate Early Development Full Field Development Bakken 27, net surface acres 1Q 218 avg. 74 MBOED (82% oil) MRO Oil Production 1Q18 Northern Delaware >9, net surface acres 1Q 218 avg. 16 MBOED (63% oil) STACK / SCOOP >3, net surface acres 1Q 218 avg. 75 MBOED (28% oil) Permian (Midland) International and Other (Brent) Oklahoma (Cushing) Bakken (Clearbrook) Eagle Ford (LLS) Eagle Ford 145, net surface acres 1Q 218 avg. 14 MBOED (61% oil) 5

6 Avg. Cum Production (MBOE) Actual LL MBOED Co-Op Wells to Sales Strong 1Q 218 Eagle Ford Results Expanding the Core Production Volumes and Wells to Sales 12 9 Production averaged 14 net MBOED; approximately flat to 4Q gross operated wells to sales 4 3 Avg. IP 3 rates of ~1,75 BOED (64% oil) 2Q 217 3Q 217 4Q 217 1Q 218 Significant free cash flow with strong LLS-based oil realizations Production Gross Wells Net WI Wells Well Performance History Expanding the core through continued improvement in well performance Atascosa County wells continue to outperform: 11 wells with average 3-day IP rates of 1,615 BOED (76% oil) 5 Strong results from Carpenter Kellner pad with average IP 3 rates of ~1,69 BOED (78% oil) Days MRO operated wells across all formations 6

7 Positive 1Q 218 Results Across Eagle Ford Position Carpenter Kellner 4 well pad Avg: 1,688 BOED (78% oil) ~6,57 LL Wilson Karnes Labus Pitman 3 well pad Avg: 1,373 BOED (79% oil) ~4,8 LL Henke Unit B 3 well pad Avg: 1,5 BOED (78% oil) ~4,59 LL Zaeske Eckols Unit 2 well pad Avg: 1,654 BOED (73% oil) ~4,75 LL May Chapman 4 well pad Avg: 1,678 BOED (76% oil) ~5,92 LL Atascosa May B 4 well pad Avg: 2,54 BOED (44% oil) ~8,18 LL Guajillo West 4 well pad Avg: 1,635 BOED (73% oil) ~5,43 LL Bee Hollman Unit 3 well pad Avg: 2,11 BOED (48% oil) ~7,17 LL Nitsch Unit A 3 well pad Avg: 2,258 BOED (26% oil) ~5,69 LL Live Oak Davila Graham 4 well pad Avg: 1,66 BOED (64% oil) ~7,14 LL IPs shown are 3 day (includes oil, NGL and gas) 7

8 Avg. Cum Production (MBOE) MBOED Operated Wells to Sales Bakken Delivering Record Wells in 1Q 218 Production Volumes and Wells to Sales 8 3 Production averaged 74 net MBOED, up 7% from 4Q Q 217 3Q 217 4Q 217 1Q 218 Production Gross Wells Net WI Wells Well Performance History gross operated wells to sales Hector success expanding the core Six wells reached IP 3 rates averaging ~2,6 BOED (81% oil) Arkin well sets new basin Three Forks record with IP 3 oil rate of 3,4 BOPD Continued outperformance in West Myrmidon 2 record Williston Basin wells from June and Chauncey at 3,47 BOPD avg. IP3 1,875 BOED and 7,57 BOED IP24s from the Mark and Wilbur wells Testing Elk Creek and Ajax in 218 Includes MRO operated wells across Bakken & Three Forks formations. 218 excludes one well with mechanical issues 8

9 3-day IP (BOPD) 3-day IP (BOPD) Record Setting Bakken Performance Hector success continues to expand the core Historic Middle Bakken Well Performance June & Chauncey 3,5 3, 2,5 2, Sherman Pad June & Chauncey 3-day avg: 4,48 BOED (77% oil) Wilbur IP24 7,57 BOED Myrmidon Mountrail Hunts Along Pad Mark IP24: 1,875 BOED (75% oil) 1,5 1, 5 McKenzie MRO Wells MRO 1Q 18 MRO Hector Wells Peers Elk Creek Dunn Kevin Buehner 11 Pad Historic Three Forks Well Performance Arkin 3, Olea TFH IP24: 7,877 BOED (83% oil) 3 wells (includes Arkin) 3-day avg: 2,862 BOED (82% oil) 2,5 Kevin Buehner 31 Pad 2, 1,5 1, Hector 3 wells 3-day avg: 2,336 BOED (8% oil) 5 MRO Wells MRO 1Q 18 MRO Hector Wells Peers Ajax Q1 218 to sales Q2 218 to sales * Source: Drilling info, competitor presentations and internal data. External data available through 1Q

10 MBOED Co-Op Wells to Sales Oklahoma Delivered 25% q/q Oil Growth in 1Q 218 Production Volumes and Wells to Sales 8 3 Production averaged 75 net MBOED; up 17% from 4Q 217; oil up 25% gross operated wells to sales; 14 were leasehold or delineation tests 2 1 >9% HBP d in STACK by YE18 2Q 217 3Q 217 4Q 217 1Q 218 Production Gross Wells Net WI Wells Total Operated STACK DSUs 7% 3% over pressured normally pressured Completion / Productivity Well Costs Spacing / Landing Zone 95% of remaining 218 wells to sales in over pressured STACK and SCOOP Optimizing value in the STACK Q1 normally pressured Meramec black oil SL wells averaged $4MM CWC Further opportunity to reduce well costs including self-sourcing local sand Leveraging infill pilot data and advanced predictive modeling to optimize well spacing and completions designs Optimizing Value per DSU 1

11 218 Oklahoma Activity Dominated by Infill Drilling All remaining infills are over pressured STACK and SCOOP Olive June Blaine Kingfisher Ruthie Irven John Mike Stroud BIA Roser Siegrist Canadian HR Potter J&M BIA Caddo Grady Lightner 3R Wet Gas Condensate Oil 2Q 218 Infill Pilots to Sales 218 Infill Pilots to Sales 218 Infill Pilots Drilled Stephens 11

12 MBOED Co-Op Wells to Sales Northern Delaware Production up 45% q/q in 1Q 218 Production Volumes and Wells to Sales Q 217 4Q 217 1Q 218 Production Gross Wells Net WI Wells Q1 218 Pads to Sales Production averaged 16 net MBOED; up 45% from 4Q gross operated wells to sales Average IP 3 rates from 7 were 1,46 BOED (69% oil) from 3 rd Bone Spring, 2 nd Bone Spring, and Upper Wolfcamp 2 wells from the Cypress infill pilot came online in the last week of the quarter, ahead of schedule Since 4Q 217, trades and a small bolt-on acquisition added 165 risked gross company operated locations at 65% average WI >5% of remaining 218 oil production hedged through favorable basis swaps 12

13 International E&P Highlights EG consistently delivering free cash flow World Class Gas Infrastructure EGLNG Plant International E&P production averaged 114 net MBOED in 1Q 218 Proven EG integrated gas assets with low capital demands Alba Gas Plant $52-58MM of EG EBITDAX expected for full year 218 at average $65 Brent World class reliability and operational excellence Unique infrastructure well positioned for additional equity and 3 rd party gas volumes AMPCO Methanol Plant HOA signed to process gas from NBL s Alen field, which extends LNG plant life and allows us to capture additional Alba field gas Signed agreement to divest the Atrush block in Kurdistan for $6MM See the 1Q 218 Investor Packet at for non-gaap reconciliations 13

14 Key Takeaways First Quarter 218 Strong 1Q18 production growth; 218 guidance raised, $2.3B development capital budget unchanged >5% of crude volumes tied to Brent or LLS pricing 65% y/y improvement in CROIC at $65 WTI Strong Eagle Ford and Bakken performance continues to expand the core Captured a largely contiguous position in emerging Louisiana Austin Chalk play at <$9 / acre Recent Highlights Bakken s Hector performance continues to impress; Olea Three Forks well reports IP24 rate of 7,877 BOED Signed agreement to divest the Atrush block in Kurdistan for $6MM Signed HOA with the EG government and NBL to process gas from NBL s Alen field through EGLNG 14