Scotia Howard Weil Energy Conference Lee Tillman President & Chief Executive Officer

Transcription

1 Scotia Howard Weil Energy Conference Lee Tillman President & Chief Executive Officer March 26, 2018

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, 2018 capital plans, cost and expense estimates, cash flows, uses of excess cash, returns, including CROIC and CFPDAS, cash margins, asset sales and acquisitions, 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 2017 Annual Report on Form 10-K, Quarterly Reports on Form 10-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. 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 4Q 2017 Investor Packet. 2

3 Key Messages Exceeded 2017 production guidance within cash flow including dividend at $51 WTI; sold Canadian Oil Sands & acquired Northern Delaware Self-funding 2018 development capital at $50 WTI including dividend; ~$500MM incremental operating cash flow at $ year over year improvement in corporate cash returns significantly outpaces production growth Margins naturally expand as U.S. resource plays receive >90% of capex and increase to ~70% of 2018 production mix Closed $450MM Libya sale on March 1 st ; 7 th country exit since 2013 Resource play leasing and exploration captured ~200,000 net acres for <$1,000 / acre 3

4 Rate of Change on Corporate Performance Metrics 2018 vs 2017 Metrics At $50 WTI At $60 WTI CROIC 1 improvement: 30% 50% CFPDAS 2 improvement: 10% 30% Total production Boe growth: Oil growth: Resource play production (Oil & BOE) 10-14% 16-20% 20-25% CROIC and CFPDAS adopted as executive compensation metrics in 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 See the 4Q 2017 Investor Packet at for non-gaap reconciliations

5 % Total Spend/Budget Successful Portfolio Transformation Continues 7 Country exits since 2013 Libya Oil Sands Mining* ~$4.2B in divestitures Since 2016 $450MM $2,500MM Simplifying & concentrating portfolio Shift to lower cost, higher margin U.S. resource plays : Exited Angola and Norway Wyoming Other $870MM $390MM 2015: Strategic decision to exit conventional exploration 100% 17% 18% 16% 7% 8% 2016: Wyoming and other non-core asset sales; STACK acquisition 80% 60% 40% 20% 71% 73% 82% 92% 92% 2017: Canadian Oil Sands divestiture; Northern Delaware acquisitions 2018: Libya divestiture; progressing Kurdistan exit 0% E Resource Plays Conventional Exploration OSM Other 5

6 EBITDAX / BOE % U.S. Resource Plays Transformation Drives Mix Shift and Margin Uplift U.S. Resource Plays % of Total Production Mix* +20% U.S. resource plays production contribution up significantly from % ~70% Production % increasing ~70% of 2018 production mix from higher margin U.S. resource plays and trending higher E MRO EBITDAX Margins* WTI $60 Estimated 2018 EBITDAX unit margins up ~35% from 2015 on a price normalized basis WTI $49 +35% WTI $50 Margins increasing Grows to ~60% increase at $60 WTI Reflects portfolio transformation and reset of cost structure E 6 *Excluding Libya

7 >90% 2018 Development Capital to U.S. Resource Plays 2018 Development Capital Budget $2.3B Eagle Ford 31% Bakken 26% 2018 Overview Disciplined capital program balances returns and strategic objectives with growth as an outcome $2.3B Development Capital Budget in 2018; cash flow neutral at $50 WTI Other* 8% Northern Delaware 17% Oklahoma 18% Uses of excess cash Preserve financial flexibility Resource play leasing and exploration (REx) Bolt-on acquisitions in core basins Additional return of capital to shareholders 7 *Other includes International and corporate capex

8 Avg. Cum Production (MBOE) Actual LL Eagle Ford Sets Execution Standard 2018 Capex: ~$710MM 12% 4% 84% D&C Co-Op D&C Non-Op Facilities & Other 2017 Highlights 180d cumulative well production increased ~20% from 2016 Set avg. single well drilling pace record with >4,200 ft/day Increased proppant loading while maintaining operational efficiency MoPo Austin Chalk well produced ~ 500 MBO in just over 1 year 180 day Cumulative Well Production Days Outlook Maintain flat production and generate free cash flow gross operated wells to sales 2/3 s in core Karnes County; 1/3 in Atascosa County Continue to upgrade Atascosa County economics 8

9 Atascosa Results Yield Improved Returns Q wells & upcoming Q activity Labus Pittman 4 well pad Avg: 1,969 BOED (92% oil) ~5,200 LL Challenger Unit C 7 well pad Avg: 1,698 BOED (90% oil) ~5,500 LL Carpenter Kellner 4 well pad ~ 6,600 LL May Chapman 4 well pad ~ 5,921 LL Wilson Karnes Rogers Foester 5 well pad Avg: 1,678 BOED (83% oil) ~5,060 LL Guajillo Unit 8 South 5 well pad Avg: 1,730 BOED (89% oil) ~6,300 LL Atascosa Morgan/Direct Assets 6 well pad Avg: 1,492 BOED (79% oil) ~6,285 LL Middle McCowen 3 well pad Avg: 2,080 BOED (94% oil) ~9,915 LL Bee Rancho Grande 3 well pad Avg: 2,429 BOED (84% oil) ~8,080 LL Q Live Oak Q IPs shown are 30 day (includes oil, NGL, and gas)

10 Avg. Cum Production (MBOE) High Confidence Bakken Delivers Strong Returns 2018 Capex: ~$590MM 2017 Highlights D&C Co-Op 180d cumulative well production increased 9% 6% D&C Non-Op >40% from 2016 Facilities & Other Top tier drilling efficiency Early Hector wells exceeding expectations Area-specific stimulation designs from 85% advanced 3D frac modeling increasing well productivity Well Performance History* Days Outlook Deliver free cash flow and growth gross operated wells to sales 2/3 s in high confidence Myrmidon development Delineation drilling in Hector and Ajax >12 years of risked gross COOP inventory at this year s planned development pace 10 *Includes all MRO operated wells across all formations

11 30 -day IP (BOPD) Bakken Best in Basin Performance Continues Hector success expanding the core Historic Industry Middle Bakken Well Performance Mountrail 3,000 2,500 Myrmidon 2,000 1,500 1, MRO Wells MRO 4Q Wells Peers Source: Drilling info, competitor presentations and internal data. External data available through 3Q McKenzie Elk Creek Big Head Pad 1 well Avg: 3,138 BOED (78% oil) Kevin Buehner 11 & 31 Pads 6 Middle Bakken / Three Forks Veronica Pad 5 wells Avg: 3,048 BOED (78% oil) Dunn Hector TAT 34 Pad 4 wells Avg: 2,789 BOED (78% oil) Q Q Ajax Chapman Pad 3 wells Avg: 1,810 BOED (85% oil) IPs shown are 30 day (includes oil, NGL and gas) 11

12 MBOE Oklahoma 2018 Focus on Overpressured STACK 2018 Capex: ~$410MM 2017 Highlights D&C Co-Op Production increased 54% from % D&C Non-Op Consistent outperformance of STACK volatile Facilities & Other oil wells Successful 1st STACK volatile oil infill development: 9 new wells (8 XLs and 1 SL) 81% averaged IP 30 of 1,840 BOED (60% oil) Strong 2017 STACK VO Results Tan Infill Wells 2017 MRMC VO Wells MRMC VO XL Type Curve Days 2018 Outlook Self-funding growth with secondary target delineation gross operated wells to sales (1H18 weighted) Pacing infills to optimize development strategy Testing lower cost completions in normally pressured window 12

13 Multi-well Pads Comprise >80% of 2018 Drilling Program 7 STACK Meramec infill pilots Blaine Kingfisher 1 STACK Meramec / Woodford infill pilot Canadian Grady Caddo Wet Gas Condensate Oil Stephens Garvin 2 SCOOP Woodford infill pilots 13

14 IP30 BO* Building Northern Delaware Momentum 2018 Capex: ~$380MM 5% 11% 84% D&C Co-Op D&C Non-Op Facilities & Other 2017 Highlights Doubled production since mid-year close Avg. IP30s from 11 wells in 4Q of 1,835 BOED Drilling costs down 20% while achieving >1,000 ft./day in Malaga Wolfcamp Zipper fracs improving completion times by 45% 2017 Eddy County Peer Well Performance 1,400 1,200 1, A MRO B C D E F G H I 2018 Outlook Deliver growth while delineating and defining upside gross operated wells to sales >75% pad drilling 60-65% average WI Focus on Wolfcamp X-Y & 3rd Bone Spring De-bundled completion services enhancing value 14 * Normalized to 4,700 LL; Eddy Co, NM wells online in 2017 with at least two months of public production data available Peer group (5+ wells): APA, CXO, DVN, Mewbourne, MRO, MTDR, OXY, WPX, XEC, XOM

15 Strong Malaga-Focused 4Q17 in Northern Delaware 1Q18 activity in Red Hills, Ranger and Malaga Ranger Arrowhead Q Wells to sales (8 pads) Avg: 1,835 BOED China Draw Ranger Q Well to Sales Malaga Q Wells to Sales Malaga Red Hills Red Hills Q Wells to Sales Eddy Lea 15

16 Returns-Driven 2018 Development Capital Program Concentrated Capital Allocation Resource Plays >90% Capital allocation drives corporate returns resulting in strong oil growth Self-funding at $50 WTI including dividend $500MM incremental operating cash flow at $60 WTI Improved Corporate Returns 1 $60 WTI +30% $50 WTI E High Margin Oil Growth +18% FY 2017 FY 2018E 16 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 Stockholder s Equity + average Net Debt)