CORPORATE PRESENTATION. November 2018

Transcription

1 CORPORATE PRESENTATION November 2018

2 Forward-looking Statements This presentation contains projections and other forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933 and Section 21E of the U.S. Securities Exchange Act of These projections and statements reflect the Company s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company s periodic reports filed with the U.S. Securities and Exchange Commission. Contact: Karen Acierno Director Investor Relations kacierno@cimarex.com Cimarex Energy Co Lincoln Street, Suite 3700 Denver, CO

3 Cimarex Energy Snapshot NYSE symbol: XEC Market Cap 1 : $8.0 billion Enterprise Value 1 : $8.6 billion Debt/EBITDA 2 : 1.1x Annual Dividend 3 : $0.72 (0.9% yield) Daily Production: 219 MBOE, 64 MBO 2018E Capex: $1.6-$1.7 billion 2018E Production Growth: 17%-18% 1 As of November 5, As of and for the twelve months ended 6/30/18. See Appendix for non-gaap definitions and reconciliations to nearest comparable GAAP measure. 3 Annualized yield of announced 3Q18 dividend 3

4 Cimarex Energy Overview Enduring Culture Maximizing full-cycle return on invested capital Proven Track Record Creating value, generating top-tier returns Premier Portfolio Profitable Growth Strong Financial Position Core positions in the Permian and Anadarko Basins Trailing 10-year average CROCE: 30% 10-year production growth CAGR: 11% Low leverage and liquidity provides opportunities 4

5 The Culture of Cimarex Idea Generation Driven by Rigorous Technical Evaluation Lookback Evaluation Improves Economic Returns, Operational Efficiencies Maximize Full-Cycle Returns Acreage Concentration Increasing Economies of Scale, Returns Financial Discipline Strong Returns, Cash Flow Growth, Liquidity, Optionality Focused Execution Focused on Maximizing IRR, NPV Inventory Expansion Innovation and Exploration 5

6 What are Fully-Burdened Returns? Half-Cycle vs Fully-Burdened Returns (% of Fully-Burdened Investment vs IRR) 100% 90% 80% Half-Cycle 70% 60% 50% Fully- Burdened 40% 30% 20% 10% 0% Drilling & Completion Midstream SWD Overhead Land - $1,500/acre % of Fully-Burdened Investment ATAX IRR 2017 XEC project, includes 36 gross wells. Flat oil & natural gas realized prices of $55.00/$2.00 6

7 History of Outsized Returns Cash Return on Capital Employed (CROCE) XEC vs S&P 500 E&P Peers 50% 40% 30% 20% 10% 0% XEC Peer Avg.*** 7

8 XEC Generating Top-Tier Returns 2018 Cash Return on Capital Employed (CROCE) XEC vs S&P % 25% CROCE (%) 20% 15% Average 10% 5% 0% Source: Stifel estimates E&P estimates based on Stifel estimates, S&P 500 estimates based on consensus CROCE = (CFFO + Interest (1-tax))/ (Avg Capital Employed) 8

9 Delaware Basin Overview 259,000 total net acres 70% of 2018 D&C Budget Currently running 12 rigs, 2 completion crews Stacked pay opportunities provides multi-zone development opportunities Upper and Lower Wolfcamp Second and Third Bone Spring Avalon Wolfcamp Bonesprin Spring Avalon 9

10 Well Productivity Improvements Long Lateral Upper Wolfcamp Wells (Culberson and Reeves Counties) Completion Generation IP180 (BOE/d) 2,000 1,500 1, ,000-ft. lateral Upper Wolfcamp wells drilled in Permian Basin since 2013 Improvement in well productivity seen through enhanced completion design Returns get better with each design change Current wells have IRRs that range from % ATAX Provides strong fully burdened returns 0 Gen 1 Gen 2 Gen 3 Gen 4 Oil (b/d) 10

11 Permian Basin Oil Takeaway Sales agreements in place for oil volumes through 2019 Strategic partnerships in core areas Pipelines in place Purchase obligations Midland index pricing ~70% of oil production on pipe; increasing to >80% by YE18 Plains pipeline Plains pipeline (under construction) Energy Transfer pipeline Offloading Site 11

12 Permian Basin Residue Gas & NGL Takeaway Sales agreements in place 98% of forecasted production through December 2019 El Paso or Waha index pricing Own and operate two gas gathering systems Triple Crown Culberson/Eddy Counties Matterhorn Reeves County Connected to multiple gas processors with inter- and intrastate outlets Long-term sales agreements in place for NGL volumes 12

13 Delaware Basin Culberson/White City Low er Wolfcamp Carry Back 6 State A 1H 4,220 BOE/d, 2,446 b/d Upper Wolfcamp Operated SWD Animal Kingdom 8 Wells Flowing Back 100,000+ net acres, JDA with Chevron in Culberson 25% of 2018 D&C capital Targeting Upper and Lower Wolfcamp, Bone Spring Western delineation continues to unlock value Six well average: 30-day IP of 3,427 Boe/d (56% oil) Animal Kingdom: (WOC) Lower Wolfcamp 8 wells testing 14 wells/section Animal Kingdom spacing Lower Wolfcamp ,216 1,216 13

14 Resilient Long Lateral Returns Culberson Long Lateral Wolfcamp BTAX IRR* 400% 300% 200% 100% 0% $30 $40 $50 $60 $70 Realized Oil Price Upper Wolfcamp - $2/Mcf Upper Wolfcamp - $1/Mcf Lower Wolfcamp - $2/Mcf Lower Wolfcamp - $1/Mcf *Assumes full NGL recovery, NGL price is 30% of oil price 14

15 Delaware Basin Reeves County Snowshoe Pagoda State Wood State Upper Wolfcamp Operated SWD 61,853 net acres 25% of 2018 D&C capital Targeting Upper Wolfcamp Wood State: 12 well/section Development wells 28% above parent wells Pagoda State: 16 wells/section Development wells 16% above parent wells Snowshoe: 18 wells/section 8 wells test flowing back 15

16 Delaware Basin Lea County Upper Wolfcamp Avalon Bone Spring Triste Draw Vaca Draw Red Tank Red Hills Red Hills Unit 17 5,164 BOE/d, 3,611 BO/d 31,384 net acres 12% of 2018 D&C capital Targeting Upper Wolfcamp, Avalon, Bone Spring Vaca Draw Lease IP30s: Upper Wolfcamp: 4,645 BOE/D (3,032 BO/D) Avalon: 2,733 BOE/D (2,051 BO/D) Leonard: 3,413 BOE/D (2,522 BO/D) Triste Draw (Avalon) 6 wells testing 20 wells/section, completing 16

17 Mid-Continent Overview 14N10W Cana Core Lone Rock 326,000 net acres 30% of 2018 D&C capital Woodford: 135,625 net undeveloped acres Participated in >950 wells Meramec: 116,500 net acres 14N-10W area: formulating Woodford/Meramec co-development plans Operate 90% of ~24,000 gross acres, 60% WI $2 billion development (net) Successfully tested 19 wells/section (Leon Gundy) 17

18 Mid-Continent Meramec 5,000 ft Meramec 10,000 ft Meramec Meramec play outline 14N10W Lehman Steve O Miss Mary 116,500 net acres 100% HBP 15% of 2018 D&C capital 40 industry development pilots active, XEC has interest or data in Developments Steve O: 6 wells on 8 well spacing (flowing back) Lehman: 4 wells on 6 well spacing Miss Mary: 3 wells on 8 well spacing 18

19 Mid-Continent Woodford 14N 10W Lone Rock Shelly Operated well Non-operated well Kim Anderson Farm 1-23H 2,164 BOE/d, 717 b/d Sweeny 8.24H 1,755 BOE/d, 667 b/d JD Hoppinscotch 135,625 net undeveloped acres 15% of 2018 D&C capital Lone Rock (16,000 net acres) yielding best Woodford results to date, completion optimization driving results Shelly: 5 wells testing 8 and 12 wells per section (flowing back) JD Hoppinscotch: 4 wells on 8 well spacing (flowing back) 14N-10W area: formulating development plans 19

20 Cash Operating Margin Expansion Declining LOE and Increasing Realized Prices Driving Margin Expansion 70% $35 60% $30 50% $25 Margin % 40% 30% 20% $20 $15 $10 $/Boe OPEX & Margin 10% $5 0% 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Cash Operating Costs Margin Margin % $0 Cash operating costs include: LOE, Transportation, Production Tax, G&A Realized prices exclude hedge gain/loss 20

21 2018 Program Overview Capital Program ($mm) 2018E E&D Capital $1,600 - $1,700 D&C Capital $1,300 - $1,400 Midstream/Other $80 - $90 D&C as % of E&D Permian Mid-Continent 82% 70% 30% Production - MBOE/d Production Guidance 2018E Total (MBoe/d) Oil(MBbls/d) Pro Forma* Y/Y Growth 2018E Total (MBoe/d) 17% - 18% Oil(MBbls/d) 21% - 23% 1QA 2QA 3QA 4QE 2018E OIL Net Wells Online 2018E *Pro forma excludes Ward County volumes 1QA 2QA 3QA 4QE Wells Drilling or WOC at Mid-Continent Permian 12/31/18 21

22 Disciplined Financial Positioning Significant Liquidity $1.9 billion of liquidity, including $864mm of cash (3Q18) Conservative Leverage 1.1x Debt/TTM EBITDA (3Q18) Investment Grade Debt $750 million 3.900% senior unsecured notes due in 2027 $750 million 4.375% senior unsecured notes due in 2024 XEC Debt/EBITDA 3.0x 2.5x Debt/TTM EBITDA 2.0x 1.5x 1.0x 0.5x 0.0x Q18 Debt/TTM EBITDA Average 22

23 Positioned for Success Enduring Culture Maximizing full-cycle return on invested capital Idea driven, technical emphasis Premier Portfolio Generating strong returns Decades of top-tier inventory Profitable Growth 2018 Oil Production Growth: 21%-23% Strong Financial Position Low leverage and liquidity provides opportunities 23

24 Appendix 24

25 2018 Guidance 4Q18E FY18E Production (MBOE/d) Oil Production (MBbls/d) Capital Expenditures ($billion) E & D $ D & C $ Midstream/Other $ Expenses ($/BOE) Production $ Transportation, processing & other $ DD&A and ARO accretion $ General and administrative $ Taxes other than income (% of oil and gas revenue) % 25

26 Hedges as of October 30, 2018 OIL WTI Oil Collars Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Volume (Bbl/d) 37,000 31,000 31,000 24,000 16,000 8,000 Weighted Average Floor Weighted Average Ceiling WTI Swaps 2 Second Quarter Volume (Bbl/d) 29,000 29,000 29,000 24,000 16,000 7,000 7,000 GAS Weighted Average Differential 3 (5.01) (5.46) (5.46) (6.50) (7.79) (0.40) (0.40) PEPL Collars 4 Volume (MMBtu/d) 123, , ,000 90,000 60,000 30,000 Weighted Average Floor Weighted Average Ceiling El Paso Perm Collars 5 Volume (MMBtu/d) 86,630 80,000 80,000 60,000 30,000 10,000 Weighted Average Floor Weighted Average Ceiling Waha Collars 6 Volume (MMBtu/d) 26,630 30,000 30,000 30,000 30,000 20,000 Weighted Average Floor Weighted Average Ceiling Total Natural Gas Collars Volume (MMBtu/d) 236, , , , ,000 60,000 Notes: 1 WTI refers to West Texas Intermediate oil prices as quoted on the New York Mercantile Exchange 4 PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent as quoted on Platt s Inside FERC 2 Index price on basis swaps is WTI Midland as quoted by Argus Americas Crude 5 El Paso Perm refers to El Paso Permian Basin index as quoted on Platt s Inside FERC 3 Index price on basis swaps is WTI NYMEX less weighted average differential shown in table 6 Waha refers to West Texas Natural Gas Index ( Waha ) as quoted in Platt s Inside FERC. 26

27 Permian Region Production Daily Production (BOE) Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Oil NGL Natural Gas 27

28 Mid-Continent Region Production Daily Production (MBOE) Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Oil NGL Natural Gas 28

29 Permian Basin Water Management Saltwater Disposal System Own and operate salt water disposal (SWD) systems in Culberson, Eddy and Reeves Improves operating costs Recycling produced water for completion operations 40% of total water procured in 2017 was recycled Cost savings of ~$1.10/bbl of water Culberson Wolfcamp wells use 87% recycled water for completions; Reeves Wolfcamp wells use 46% Secured SWD agreements in Lea County 29

30 Investment Sensitivities Highlight Asset Quality and Depth Capex Production Growth (3-Yr CAGR) Cumulative Free Cash Growth Sensitivities ($mm) Boe Oil Flow ($mm)* CROCE Maintenance Case 700 Flat Flat Growth Sensitivity 1,200 10% 13% $500-$600 30% *Assumes $55/$2.00 realized prices *Free cash flow is defined as cash provided by operating activities less D&C capital, capitalized overhead, production and midstream capital and dividends. It excludes proceeds from announced asset sale. Assuming 10% annual production CAGR over the next three years, Cimarex can generate $ mm of cumulative free cash flow 30

31 Permian Basin Development Pilot Details Culberson Lower Wolfcamp - Animal Kingdom Eight wells testing 14 wells per section Waiting on completion Red Hills (Lea) Upper Wolfcamp - Hallertau Six wells testing 12 wells per section Producing Reeves Upper Wolfcamp - Snowshoe Eight wells testing 18 wells per section Currently completing Lower Wolfcamp Upper Wolfcamp Upper Wolfcamp Animal Kingdom spacing 225 1, ,216 Hallertau spacing Snowshoe spacing Red Tank (Lea) Avalon - Triste Draw Six wells testing 20 wells per section Waiting on completion Avalon Triste Draw spacing

32 Non-GAAP Reconciliation Reconciliation of Net Income to EBITDA and Adjusted EBITDA 1 ($ in Millions) LTM 9/30/18 Net income (loss) $ (2,580) $ (409) $ 494 $ 650 Income tax expense (benefit) (1,472) (214) Interest expense, net of capitalized DD&A and ARO accretion EBITDA (3,256) (161) 1,196 1,400 Impairment of oil and gas 4, Adjusted EBITDA ,196 1,400 Debt Adjusted Shares (Using trailing 12-mo (TTM) stock price) LTM 9/30/18 Basic shares outstanding (in 000s) 95,124 95,437 95,603 Debt adjusted shares outstanding YE Debt, net 847,124 1,099, ,054 TTM stock price Equivalent shares issued using TTM stock price 7,362 9,644 6,210 Debt adjusted shares using TTM stock price 102, , ,813 1 The above table provides a reconciliation from generally accepted accounting principles (GAAP) net income (loss) to non-gaap EBITDA and non-gaap adjusted EBITDA, which excludes ceiling test impairments 32

33 Non-GAAP Reconciliation Reconciliation of cash flow from operations 1 Nine Months Ended September 30, Debt/Cap calculation ($ in Millions) Sept 30, 2018 ($ in Millions) Long-term debt (principal) 1,500 Net cash provided by operating activities $ 756 $ 1,158 Stockholders equity 3,026 Change in operating assets and liabilities 73 (52) Total capitalization 4,526 Adjusted cash flow from operations $ 829 $ 1,105 Long-term debt/total capitalization 33% Finding & development (F&D) cost Debt/Adjusted EBITDA calculation 2017 Twelve months Ended Dec 31 LTM Additions to proved reserves (MMBOE) ($ in Millions) /30/18 Revisions of previous estimates (10.0) Extensions & discoveries Long-term debt (principal) $1,500 $1,500 $1,500 Purchase of reserves 0.2 Total Additions (all sources) 147 Total Capital ($MM) $ 1,281 Adjusted EBITDA 597 1,196 1,400 Debt/Adjusted EBITDA 2.5x 1.3x 1.1x F&D Costs (all sources) ($/BOE) $ 8.71 Drilling F&D cost (extensions & discoveries) ($/BOE) $ Management uses the non-gaap measure of adjusted cash flow from operations as a means of measuring the company's ability to fund its capital program and dividends, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of cash flow from operating activities. Management believes this non- GAAP measure provides useful information to investors for the same reasons, and that it is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry. 33

34 Non-GAAP Reconciliation Cash Return on Capital Employed (CROCE) Cash Flow from Operating Activities+ After-tax Interest Expense Average Book Equity + Average Debt Cash flow from operating activities 1, ,130 1,292 1,193 1,324 1, ,097 Effective Tax Rate 37% 36% 37% 37% 37% 37% 37% 36% 34% 28% Stockholder's equity 2,349 2,038 2,610 3,131 3,390 3,834 4,332 2,458 2,043 2,568 Debt ,500 1,500 1,500 1,500 Capitalization 2,941 2,431 2,960 3,536 4,140 4,758 5,832 3,958 3,543 4,068 Interest expense Capitalized int (22) (23) (29) (29) (35) (32) (36) (31) (21) (23) Net interest exp CROCE 41% 26% 42% 40% 31% 30% 31% 16% 18% 30% 34