2019 CAPITAL PROGRAM & 2018 RESULTS. February 13, 2019

Transcription

1 219 CAPITAL PROGRAM & 218 RESULTS February 13, 219

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 219 capital budget and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production, cash margins, oil growth, cost and expense estimates, cash flows, uses of excess cash, return of cash to shareholders, returns, including CROIC and CFPDAS, and EG EBITDAX, 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, future, guidance, intend, may, outlook, 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 actual 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. This presentation includes non-gaap financial measures, including organic free cash flow and E.G. EBITDAX. 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 4Q18 Investor Packet. 2

3 Framework for Success Our working definition of capital discipline Committed to our Framework Corporate Returns Portfolio transformation and focused capital allocation drive multi-year corporate returns improvement through capital efficient oil growth Free Cash Flow Sustainable free cash flow at conservative pricing Return of Capital Differentiated Execution Return incremental capital to shareholders in addition to peer competitive dividend; funded through free cash flow, not dispositions Continuous improvement in capital efficiency and operating costs while enhancing our resource base; delivering on our commitments Powered by our Foundation Multi-Basin Portfolio Balance Sheet Strength Capital allocation flexibility, broad market access, supplier diversification, rapid sharing of best practices, platform for talent development Financial flexibility to execute business plan across broad range of pricing; current net debt/ebitdax among lowest in peer group 3

4 Forward Outlook Prioritizes Returns, FCF, Return of Capital 1 Organic FCF positive in both 219 and 22 above $45/bbl WTI, post-dividend Corporate Returns Free Cash Flow Return of Capital Differentiated Execution Continues multi-year rate of change improvement in key enterprise performance metrics 2% CROIC and 18% CFPDAS CAGRs (217-22) at $5/bbl WTI flat 3% CROIC and CFPDAS CAGR (217-22) at $6/bbl WTI flat Organic FCF positive above $45/bbl WTI in both 219 and 22 Portfolio delivers strong two-year (219-22) organic FCF >$75MM at $5/bbl WTI flat >$2.2B at $6/bbl WTI flat Continue to prioritize return of capital Returned over 25% of operating cash flow to shareholders in 218 Return of capital metric incorporated into executive compensation scorecard, complementing CROIC and CFPDAS High value oil growth exceeds BOE growth, an outcome of returnsfirst capital allocation 219 U.S. oil growth of 12% and total oil growth of 1% Maintaining focus on organic resource base enhancement 4 1 Organic FCF = Operating Cash Flow before working capital (excl. exploration costs other than well costs), less Development Capex, less Dividends, plus EG return of capital & other 2 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); 3 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; See the 4Q 218 Investor Packet at for non-gaap reconciliations

5 Cumulative Organic FCF ($MM) Organic FCF Yield (Annual Avg.) Sustainable FCF in 219 & 22 at Conservative Pricing Differentiated annual FCF yield vs. E&P peers 2,5 $2.2B+ Cumulative Organic FCF 1% 2, 1,5 1, 5 Organic FCF+ Above $45/bbl in Both Years $75MM+ Cumulative Organic FCF 5% ($45 WTI) ($5 WTI) ($6 WTI) % Organic FCF Organic FCF Yield (Annual Avg.) *Organic FCF yield represents average annualized yield for 219 and 22 using MRO stock price as of 2/8/19 5

6 Differentiated Execution Led the Way in 218 Underpins confidence in 219 delivery 218 Objectives Initial WTI Actual WTI Capital Discipline $2.3B development capital $2.3B development capital Corporate Returns 3% CROIC improvement 78% CROIC improvement 1% CFPDAS improvement 65% CFPDAS improvement Free Cash Flow Return of Capital Capital Efficient Oil Growth Organic FCF positive, postdividend, above $5/bbl WTI Prioritize incremental return, above dividend, through sustainable organic FCF 18% total oil growth at midpoint, divestiture adjusted 22.5% resource play oil growth at midpoint $865MM of post-dividend, organic FCF $7MM of share buybacks and $17MM dividend 24% total oil growth, divestiture adjusted 32% resource play oil growth 6

7 219 Capital Program Overview Focused program balances corporate returns with strategic objectives Total capital program of $2.6B, down from 218 Focused Investment Comprised of $2.4B development capital and $2MM of resource play leasing and exploration (REx) capital Planning basis of $5/bbl WTI; organic free cash flow positive above $45/bbl WTI, post-dividend Over 95% of development capital allocated to U.S. resource plays Other REx Resource Play Development ~6% of resource play capital allocated to Eagle Ford and Bakken with ~4% to Oklahoma and Northern Delaware, similar to 218 Capital efficient oil growth on flat wells to sales drives corporate returns improvement Resource Play Capital Allocation Development capital continues to fund organic resource base enhancement initiatives Year-over-year reduction in REx capital reflects more ratable forward spending profile Continues progression of LA Austin Chalk and other emerging opportunities with focus on full cycle returns Northern Delaware Oklahoma Eagle Ford Bakken 7

8 219 Basin Level Highlights and Objectives Competitively advantaged multi-basin model Appraise / Delineate Early Development Full Field Development Bakken gross operated wells to sales 9% Myrmidon and Core Hector Continue organic enhancement initiatives Returns, free cash flow, oil growth Oklahoma 55-6 gross operated wells to sales Development focus on overpressured STACK and SCOOP; 95% pad drilling Secondary target delineation Predictability and competitive returns Northern Delaware 55-6 gross operated wells to sales Focus on Malaga Upper Wolfcamp and Red Hills delineation Transition to multi-well pads Returns, oil growth, and margin enhancement Eagle Ford gross operated wells to sales 9% Karnes and Core Atascosa Continue organic enhancement initiatives Progress multi-well Phase 2 enhanced oil recovery (EOR) pilot Returns and free cash flow 8

9 218 Highlights Full-year 218 Highlights Delivered capital discipline, corporate returns improvement, free cash flow generation, and enhanced return of capital to shareholders Drove capital efficiency improvement leading to high margin oil growth outperformance Enhanced resource base through core extension tests in Eagle Ford and Bakken; progressed REx program with focus on full-cycle returns 125% reserve replacement at <$12.5/BOE Closed $45MM Libya sale; received final Oil Sands Mining payment of $75MM Further strengthened balance sheet and financial flexibility by increasing cash and cash equivalents by ~$9MM to $1.5B at YE 218 4Q 218 Highlights $255MM of organic FCF Development capex down 1% sequentially to ~$5MM Another quarter of differentiated multi-basin execution and capital efficiency improvement Eagle Ford: 38 wells achieved an avg. IP 3 of 1,81 BOED (72% oil) Bakken: Ajax four-well pad extension test achieved avg. IP 3 of 2,37 BOED (81% oil) at ~$5MM completed well cost (CWC) Oklahoma: 3R SCOOP infill >6% above type curve at 45 days; positive Springer delineation well Northern Delaware: 4 Upper Wolfcamp wells avg. IP 3 of 34 BOED/1, ft. lateral (74% oil) 9

10 $MM Total Company Cash Flow for 218 Generated ~$865MM of organic free cash flow at avg. WTI of $65/bbl $2.3B annual development capital budget unchanged throughout year $7MM of stock buy-backs and ~$17MM of annual dividend; over 25% of operating cash flow returned to shareholders in 218 $369MM REx Capex more than fully funded by disposition proceeds 4, 3,5 3, 2,5 2,286 2, 3,245 1,5 1, /1/18 Cash Balance Operating Cash Flow b/f WC 1 Development Capital Expenditures 169 Dividends 78 EG LNG Return of Capital & Other 369 1,151 1, ,462 Cash Balance b/f A&D, REx & Financing REx Capex Share Buy- Back Acquisitions & Disposal of Assets (Net) 2 51 Total Working Capital 3 12/31/18 Cash Balance 1 1 Excludes $34MM of exploration costs other than well costs 2 Acquisition and Disposal of Assets includes $15MM BLM lease costs, Libya disposition & OSM final payment 3 Total working capital includes $17MM and $(68)MM of working capital changes associated with operating activities and investing activities, respectively & other See the 4Q 218 Investor Packet at for non-gaap reconciliations

11 Avg. Cum. Production (MBOE) MBOED Operated Wells to Sales Standout Year for Eagle Ford on All Fronts Year-over-year growth on fewer wells to sales Production Volumes and Wells to Sales Full-year 218 Highlights oil production growth of 7% on 5% fewer gross operated wells to sales (WTS) 4 Atascosa wells achieved avg. IP 3 of 1,51 BOED (72% oil), demonstrating strength of extended core 1Q18 2Q18 3Q18 4Q18 Production Gross Wells Net WI Wells Well Performance History Compelling returns, significant free cash flow generation, improved well productivity 18-day cumulative production up 1% vs. 217 and up 45% vs Q 218 Highlights Production averaged 17 net MBOED, up 2% from year-ago quarter 38 WTS with avg. IP 3 of 1,81 BOED (72% oil) Completion stages per day up over 1% and avg. CWC per lateral foot down over 15% vs. year-ago quarter Days Well performance history composed of MRO operated wells across all formations 11

12 Strong Well Productivity from the Eagle Ford Core 4Q 218 wells driving robust corporate returns Jordan / Fransen / GM 5 well pad 1,55 BOED (69% oil) ~3,27 LL Challenger B / Medina H. 3 well pad 1,47 BOED (79% oil) ~5,23 LL CRH / Fire Opal 3 well pad 1,8 BOED (73% oil) ~5,5 LL Wilson Medina-Jonas 6 well pad 1,94 BOED (83% oil) ~6,75 LL San Christoval Ranch 3 well pad 1,64 BOED (48% oil) ~3,31 LL Guajillo East 5 well pad 1,48 BOED (82% oil) ~5,96 LL 4Q18 Pads to Sales Atascosa Live Oak Karnes Bee Brown D. / Holland B. 6 well pad 2,7 BOED (74% oil) ~6,1 LL Luna / May 4 well pad 1,48 BOED (56% oil) ~5,75 LL Kowalik 3 well pad 2,94 BOED (68% oil) ~8,95 LL IPs shown are 3-day (includes oil, NGL and gas) and represent pad average 12

13 BOED CWC ($MM) MBOED Operated Wells to Sales Bakken Performance Consistently Enhancing Value Successful core extension tests in Ajax, Southern Hector, and Elk Creek Production Volumes and Wells to Sales Q18 2Q18 3Q18 4Q18 Production Gross Wells Net WI Wells ~5% Y/Y Capital Efficiency Improvement 3, $8 +15% 2,5 $7 2, -24% $6 1,5 $5 1, $4 4Q17 4Q18 4Q17 4Q18 IP 3 BOED* CWC ($MM) Full-year 218 Highlights Capital efficient oil production growth of 53% 2 Northern Hector wells achieved avg. IP 3 of 2,39 BOED (78% oil), demonstrating strength of extended core 4Q 218 Highlights Production averaged 94 net MBOED, up 37% from year-ago quarter 27 WTS avg. IP 3 of 3,335 BOED (76% oil) Ajax four-well pad extension test achieved avg. IP 3 of 2,37 BOED (81% oil) at ~$5MM CWC Avg. IP 3 up 15% with CWC down 24% vs. yearago quarter 8 wells achieved sub $5MM CWC with avg. IP 3 of 2,85 BOED (76% oil) Completion stages per day up over 65% from yearago quarter * IP 3 rates normalized to

14 3-day IP (BOPD) 3-day IP (BOPD) Leading Williston Basin Well Productivity Delivered 45 of the top 5 all-time Middle Bakken & Three Forks oil wells Historic Middle Bakken Well Performance 4, 3,5 3, 2,5 2, 1,5 1, 5 MRO 218 MRO 217 Peers Historic Three Forks Well Performance Julia Jones Pad 5 wells 4,25 BOED (75% oil) Clara Pad 4 wells 3,51 BOED (73% oil) McKenzie Elk Creek Myrmidon Irish Pad 3 wells 3,14 BOED (74% oil) Axell, Nugget & Ness Pads 9 wells 3,45 BOED (74% oil) 5, 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 MRO 218 Peers Q4 218 to Sales Dunn Ajax Hector Ringer Pad 2 wells 2,385 BOED (84% oil) Gloria Pad 4 wells 2,37 BOED (81% oil) 14 IPs shown in map are 3-day (includes oil, NGL and gas) and represent pad average Source: Drilling info, competitor presentations and internal data. External data available through 4Q 218.

15 MBOED MBOED Operated Wells to Sales Enhanced Returns & Predictability Continue in Oklahoma SCOOP infills outperforming type curve Production Volumes and Wells to Sales Q18 2Q18 3Q18 4Q18 Production Gross Wells Net WI Wells 3R SCOOP Infill >6% Above Type Curve at 45 Days Days wps wells per section spacing Type Curve Lightner Wells - 4 wells on 8 wps 3R Wells - 8 wps Full-year 218 Highlights Successful transition to infill development in overpressured STACK and SCOOP Competitive returns and predictable results at various spacing designs Completion cost per lateral ft. down >3% from prior year 4Q 218 Highlights 67 net MBOED production, up 4% from year-ago quarter 8 well per section 3R SCOOP Woodford infill delivered avg. IP 3 of 2,6 BOED (69% liquids) CWC/lateral ft. ~35% below most recent SCOOP Woodford infill (Lightner) Springer delineation well on same pad delivers IP 3 of 1,825 BOED (81% oil) Completion stages per day up 55% from year-ago quarter 15

16 Focused on Overpressured STACK and SCOOP Multi-well development continues Olive June Blaine Kingfisher Lloyd Ruthie Canadian Calvin Ellis Caddo Burton Grady 3R 7 Woodford infill wells (8 wps) 2,6 BOED (69% liquids) ~1, LL Wet Gas Condensate Oil 4Q18 Wells to Sales Upcoming Infills Stephens Papa Pump 1 Springer delineation well 1,825 BOED (81% oil) ~8,48 LL IPs shown are 3-day (includes oil, NGL and gas) and represent pad average on the 3R, and single well on the Papa Pump 16

17 Completion stages/day MBOED Operated Wells to Sales Strategically Pacing Northern Delaware Focus on multi-well pads while progressing delineation Production Volumes and Wells to Sales Q18 2Q18 3Q18 4Q18 Production Gross Wells Net WI Wells Capturing Significant Efficiency Gains +4% 4Q17 4Q18 Stages/day Full-year 218 Highlights Risked gross company operated locations up ~2% since play entry Drilling ft. per day up >2% and completion stages per day up >3% vs. 217 Improved midstream access for all products 4Q 218 Highlights 26 net MBOED production, up 138% from year-ago quarter 12 WTS avg. IP 3 of 1,935 BOED (49% oil), or 36 BOED per 1, ft. lateral 4Q activity featured successful Lower Wolfcamp (WC) spacing test 4 Upper WC wells avg. IP 3 of 34 BOED per 1, ft lateral (74% oil) Executed comprehensive water handling agreement covering Red Hills area Completion stages per day up 4% from yearago quarter 17

18 International Highlights World Class Gas Infrastructure EGLNG Plant Plant AMPCO Methanol Plant Plant Alba Alba Gas Gas Plant Plant Full-year 218 Highlights Production of 113 net MBOED E.G. EBITDAX of over $65MM Reduced estimated U.K. asset retirement obligation by $143MM Continued rigorous portfolio management Closed $45MM Libya sale; received final Oil Sands Mining payment of $75MM Progressing full Kurdistan exit, which will mark 9 th country exit in last 5 years 4Q 218 Highlights Production of 15 net MBOED 1Q19 volume guidance includes impact of E.G. triennial turnaround E.G. EBITDAX of $153MM 18

19 Framework for Success Prioritizing Corporate Returns, FCF, Return of Capital to Shareholders While many in our industry talked about capital discipline, we delivered Through improving capital efficiency and unwavering discipline, we drove significant improvement to our corporate returns, delivered more oil growth, generated $865 million of organic free cash flow post-dividend, and returned most of that cash back to our shareholders via share repurchases. As we turn to 219 and beyond, we remain committed to this same framework for success. - Lee Tillman, Chairman, President and CEO Our Framework Corporate Returns FCF Generation Return of Capital to Shareholders Differentiated Execution Our Delivery % realized CROIC improvement $865MM of organic FCF $7MM of share buybacks Unchanged $2.3B development capital budget 24% total company oil growth vs. 18% initial guidance $369MM REx spend Our Plan Multi-year CROIC improvement Organic FCF above $45/bbl Prioritizing return of cash $2.4B development capital budget 1% total company oil growth & 12% U.S. oil growth $2MM REx budget Our Foundation Multi-Basin Portfolio Balance Sheet Strength 19

20 Appendix 2

21 219 Production Guidance FY19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED) * * United States International Total Net Production Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED) Q1 219 Q4 218* Q1 218* Q1 219 Q4 218* Q1 218* United States International Total Net Production * Divestiture-adjusted, and also excludes Atrush volumes which are held for sale 21

22 219 Cost and Tax Rate Guidance Full-Year Estimate United States Cost Data Production Operating $ DD&A $ S&H and Other* $ International Cost Data Production Operating $ DD&A $ S&H and Other* $ Expected Tax Rates by Jurisdiction: United States and Corporate Tax Rate % Equatorial Guinea Tax Rate 25% United Kingdom Tax Rate 4% * Excludes G&A expense 22

23 United States Crude Oil Derivatives As of February 12, 219 Crude Oil (Benchmark to NYMEX WTI) 1Q 219 2Q 219 3Q 219 4Q 219 FY 22 Three-Way Collars Volume (BBLs/day) 7, 7, 5, 5, - Weighted Avg Price per BBL: Ceiling $71.21 $71.21 $75.88 $ Floor $55.86 $55.86 $57.8 $ Sold put $48.71 $48.71 $5.8 $5.8 - Basis Swaps (a)/(b) Volume (BBLs/day) 1, 11, 16, 16, 15, Weighted Avg Price per BBL $(.82) $(1.6) $(1.53) $(1.53) $(.94) NYMEX Roll Basis Swaps Volume (BBLs/day) 6, 6, 6, 6, - Weighted Avg Price per BBL $.38 $.38 $.38 $ (a) The basis differential price is between WTI Midland and WTI Cushing (b) Between January 1, 219 and February 12, 219, the Company entered into 5, Bbls/day of Midland basis swaps for July - December 219 with an average price of $(2.55) and 1, Bbls/day of Clearbrook basis swaps for March - December 219 with an average price of $(3.5)

24 United States Natural Gas Derivatives As of February 12, 219 Natural Gas (Benchmark to NYMEX HH) 1Q19 Three-Way Collars Volume (MMBtu/day) 2, Weighted Avg Price per MMBtu: Ceiling $5.25 Floor $3.43 Sold put $

25 218 Volumes, Exploration Expense & Effective Tax Rate Excluding Libya 1Q 2Q 3Q 4Q Full-Year United States Net Sales Volumes: - Crude Oil and Condensate (MBD) Natural Gas Liquids (MBD) Natural Gas (MMCFD) United States Total (MBOED) International Net Sales Volumes: - Crude Oil and Condensate (MBD) Natural Gas Liquids (MBD) Natural Gas (MMCFD) International Total (MBOED) Total Sales Volumes (MBOED) Total Available for Sale (MBOED) Equity Method Investment Net Sales Volumes: - LNG (metric tonnes/day) 5,541 6,141 6,152 5,384 5,85 - Methanol (metric tonnes/day) 1,195 1,316 1,334 1,119 1,241 - Condensate and LPG (BOED) 12,416 12,689 11,942 15,71 13,34 Exploration Expenses (Pre-tax): - United States ($ millions) International ($ millions) Consolidated Effective Tax Rate (ex. Libya) Provision 2% 31% 29% 4% 14% 25

26 MBOED MBOED 4Q 218 Net Sales Volumes and Realizations U.S. Divestiture-Adj. Sales Volumes* 3 International Divestiture-Adj. Volumes** Q17 3Q18 4Q18 4Q4Q Q3Q Q4Q18 18 Available for Sale Sales Avg C&C Realizations ($/BBL) Excluding Derivatives $55.46 $68.51 $56.1 Including Derivatives Avg C&C Realizations ($/BBL)*** $54.3 $64.8 $58.25 $54.7 $62.81 $ *U.S. adjusted for divestitures of 5 MBOED in 4Q17 and 2 MBOED in 3Q18 **International available for sale volumes adjusted for divestitures/held for sale of 37 MBOED in 4Q17, 3 MBOED in 3Q18, and 3 MBOED in 4Q18. Sales volumes adjusted for divestitures/held for sale of 36 MBOED in 4Q17, 4 MBOED in 3Q18, and 3 MBOED in 4Q18 *** Adjusted the average C&C by $7.29 to exclude Libya in 4Q17 Cumulative underlift of (138) MBOE in E.G., and cumulative overlift of 6 MBOE in Kurdistan and 68 MBOE in U.K.

27 4Q 218 Production Mix Eagle Ford Oklahoma 2% 24% 48% 22% 58% 28% Total U.S. Resource Plays 23% Crude Oil/Condensate Bakken Northern Delaware 18% 59% NGLs Natural Gas 6% 6% 27% 54% 88% 19% 27

28 218 Capital, Investment & Exploration Budget reconciliation $MM 218 Budget 218 Actual Cash additions to Property, Plant and Equipment 2,753 Working Capital associated with PPE (68) Property, Plant and Equipment additions 2,685 M&S Inventory (6) REx expenditures included in capital expenditures (388) Exploration costs other than well costs (5) Development Capital 2,3 2,286 28