2018 RESULTS & 2019 OPERATING PLAN

Transcription

1 2018 RESULTS & 2019 OPERATING PLAN FEBRUARY 20, 2019

2 PLEASE READ THIS PRESENTATION MAKES REFERENCE TO: Forward-looking statements This presentation contains forward-looking statements within the meaning of securities laws. The words "anticipate," "budget," "estimate," "expect," "forecast," "guidance," "plan," "project," "target," "will" and similar expressions are intended to identify forwardlooking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward-looking statements. Forward-looking statements in this release include, among other things: guidance for 2019 and the first quarter of 2019 and the expectation that third party force majeure events should be resolved by the end of February General risk factors include the availability, proximity and capacity of gathering, processing and transportation facilities; the volatility and level of oil, natural gas, and natural gas liquids prices and related differentials, including any impact on the Company s asset carrying values or reserves arising from price declines; uncertainties inherent in projecting future timing and rates of production or other results from drilling and completion activities; the imprecise nature of estimating oil and natural gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results; the uncertain nature of joint venture or similar efforts and of expected benefits from the actual or expected joint venture or similar efforts; the availability of additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk management strategy; and other such matters discussed in the Risk Factors section of SM Energy s most recent Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission. The forward-looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except as required by securities laws. non-gaap financial measures: See Appendix for reconciliations non-gaap forward-looking metrics: See Appendix for definitions 2

3 PREMIER OPERATOR OF TOP TIER ASSETS 2018: ANOTHER YEAR OF OUTSTANDING EXECUTION Permian Production Growth (1)(2) +97% Operating Margin Increase (1) +66% PV-10 Value Creation (1)(2) +79% Long-term Debt Reduction (1) -$325MM Discretionary Cash Flow Increase (1) +53% (1) 2018 compared to 2017 (2) Based on retained assets 3

4 PREMIER OPERATOR OF TOP TIER ASSETS 2019 PLAN OBJECTIVES 1 Generate free cash flow in 2H19 2 Deliver ~20% production growth in the Permian 3 Generate solid full cycle returns from last $ spent per drilling unit 4 Maintain leverage at ~3 times net debt: EBITDAX at YE Plan based on $55/Bbl WTI oil / $3/MMBtu Henry Hub natural gas 4

5 2019 CAPITAL PROGRAM FOCUS ON HIGH MARGIN GROWTH EXPECTED CAPITAL SPEND REDUCTION > 20% (1) Total Capital Spend ~$1,000 1,070MM D&C Budget Drilling and Completion 90% 5% Facilities Other 5% Eagle Ford 20% Permian 80% Permian: ~100 net wells drilled and completed Eagle Ford: ~28 net wells drilled and ~18 net wells completed; joint venture to include 6 wells drilled and 12 wells completed at no capital cost to the Company (1) 2019 compared to

6 Production (Mboe) PLAN HIGHLIGHTS TARGETING FREE CASH FLOW 2H19 EXPECTED MIDLAND PRODUCTION UP ~135% (1) 50,000 40,000 30,000 20,000 10, e Midland Basin Eagle Ford Sold (1) Based on retained assets 6

7 2019 PLAN GUIDANCE (1) Capital & Production FY 2019 Total Capital Spend ($MM) (2) (before acquisitions) $1,000 - $1,070 Total Production (MMBoe) Total Production (MBoe/d) Oil 43 44% Costs >20% Expected Reduction in Capital LOE ($/Boe) ~$5.00 Transportation ($/Boe) ~$4.25 Production and Ad Valorem taxes ($/Boe) (4% of pre-hedge revenue + ~$0.70) G&A ($MM) includes ~$20MM non-cash compensation Exploration expense, including capitalized overhead ($MM) before dry hole expense, all of which is included in capital expenditure guidance ~$2.00 ~$120 ~$50 DD&A ($/Boe) ~$17.00 ~20% Growth in Permian Production (1) As of February 20, 2019 (2) Total Capital Spend is a non-gaap financial measure that is defined in the Appendix. The Company is unable to present a quantitative reconciliation of this forward-looking, non-gaap financial measure to the most comparable GAAP financial measure because components of the calculations, such as potential acquisitions and changes in current assets and liabilities, are inherently unpredictable. Moreover, estimating such GAAP measures with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. 7

8 Proved Reserves (MMBoe) 2018 PROVED RESERVES: ADDITIONS & REVISIONS 503 MMBOE - UP 18% (1) ; PV-10 UP 79% (1)(2) Proved reserves up 18% (1) on retained assets Net proved reserve additions were 188 MMBoe (excluding revisions), or 119 MMBoe (net of revisions) Proved reserve PV-10 of $5.1B (2) Solid production replacement YE17 Divestitures Production Adds/ Infills 49% Proved Developed 35% oil, 44% natural gas, 21% NGLs Revisions YE18 Note: Calculated in accordance with SEC Pricing at $65.56 per barrel of oil NYMEX, $3.10 per MMBtu of natural gas at Henry Hub and $33.45 per barrel of natural gas liquids ( NGLs ) at Mt. Belvieu. 1) Year-end 2018 compared to year-end 2017; based on retained assets 2) PV-10 is a non-gaap measure. See Appendix for reconciliation of PV-10 (Non-GAAP) to Standardized Measure (GAAP). 8

9 Proved Reserves (MMBoe) PV-10 (1) ($MM) PROVED RESERVES AND PV-10 (1) YE 2016 YE PORTFOLIO TRANSITION - BUILDING VALUE $6, PV-10 $5.1B $5,000 $4, PV-10 $2.8B $3,000 $2, PV-10 $0.8B $1,000 $0 Proved Reserves (on retained assets) Proved Reserves (sold) PV-10 (on retained assets) 1) PV-10 is a non-gaap measure. See Appendix for reconciliation of PV-10 (Non-GAAP) to Standardized Measure (GAAP). 9

10 MIDLAND BASIN: NEW WELL RESULTS GREAT RESULTS - NEW MIDLAND WELLS AVG 1,417 BOE/D, 89% OIL (10,523 LL) B i g I r o n 18 Wells 30 Day Avg. Peak Rate: 1,478 Boe/d (89% oil) C o y o t e Va l l e y 3 Wells 30 Day Avg. Peak Rate: 1,494 Boe/d (90% oil) S i g n a l M o u n t a i n 8 Wells 30 Day Avg. Peak Rate: 1,212 Boe/d (89% oil) MARTIN RockStar Big Iron HOWARD Coyote Valley Signal Mountain S w e e t i e P e c k 7 Wells 30 Day Avg. Peak Rate: 1,463 Boe/d (87% oil) UPTON MIDLAND Sweetie Peck 10

11 Cumulative Production (Boe) MIDLAND BASIN: ROCKSTAR NEW WELL RESULTS SM AMONG RSEG IDENTIFIED TOP 4 PERMIAN PERFORMERS YTD (1) BIG NEW WELLS SUPPORT CONTINUED TOP TIER PERFORMANCE 250, , , ,000 50, Previously Reported Well Avg Days on Production New Well Avg (2) (3) As of February 12, 2019 (1) RS Energy Group 7/9/18 - Ryan Luther, Latest Permian Well Performance Who are the True Leaders? (2) Previously Reported Well Average includes all (104) previously reported SM operated wells on production since 11/3/2016. (3) New Well Average includes 29 new wells that have not been previously reported. 11

12 Percent Improvement Sand Cost Index Indexed to Northern White Jan 18 MIDLAND BASIN: DRIVING CAPITAL EFFICIENCY COMPLETIONS EFFICIENCY AND LOCAL SAND USAGE 180% Percent Improvement in Stages Pumped Per Day Since 3Q Current Sand Costs (1) Indexed to January % 140% 120% 100% % % 40% 20% 0% % 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (1) Excludes last mile logistics as there is variability in these charges among vendors. >150% improvement since 3Q16 Maximizing local sand usage 12

13 MIDLAND BASIN 2019 PLAN FOCUSED ON EXECUTION AND RETURNS ACROSS OUR TOP TIER ASSETS P l a n O b j e c t i v e s OPTIMIZE RETURNS PER DEVELOPMENT UNIT Co-development of multiple intervals Maximize use of local sand 2019 PLAN DETAILS Deliver nearly 20% production growth Test Wolfcamp D and Dean ~100 net completions ~10,300 average lateral feet per well ~770 average spacing within zone $7.7MM average well cost ~47% Boe PDP decline (YE18 YE19) YE 2018 INVENTORY: YEARS O p e r a t i n g D e t a i l s MARTIN MIDLAND RockStar HOWARD Rigs Currently Running: Completion Crews: ~82,000 N E T A C R E S Sweetie Peck UPTON 13

14 % of IP % of IP DIFFERING DECLINE PROFILES OF LS & WCA WELLS SIMILAR RETURNS LS & WCA: SLOWER RAMP UP BUT SHALLOWER & LESS CAPEX Jester Pad Wells % OF PEAK INITIAL PRODUCTION (IP) RATES VS TIME 120% Papagiorgio Pad Wells % OF PEAK INITIAL PRODUCTION (IP) RATES VS TIME 120% 100% 100% 80% 80% 60% 60% 40% 40% 20% 20% 0% 0% JESTER WCA (BOPD/IP24HR) DAYS JESTER LS (BOPD/IP24HR) DAYS PAPAGIORGIO WCA (BOPD/IP24HR) PAPAGIORGIO LS (BOPD/IP24HR) 2019 Plan composed of 36% Lower Spraberry wells vs. 9% in

15 Production Rate (MCFD, BPD) SOUTH TEXAS: AUSTIN CHALK HIGHER LIQUID CONTENT = HIGHER RETURNS 10,000 Galvan Ranch C 917H 7,886 Lateral 30-day IP rate 2,084 Boe/d (3-stream) 1, Galvan Ranch C 917H AC Target waiting on flowback Austin Chalk AC Partial Penetration Producing AC Target 2019 drill plan Well shut-in for tubing installation 10 7/5/2018 8/5/2018 9/5/ /5/ /5/ /5/2018 1/5/2019 Production Date Dry Gas Condensate NGL Upper Eagle Ford Lower Eagle Ford 917 Buda

16 SOUTH TEXAS 2019 PLAN FOCUSED ON VALUE ENHANCEMENT AND RETURNS ACROSS TOP TIER ASSETS P l a n O b j e c t i v e s ENHANCING INVENTORY VALUE Demonstrate value enhancement from new Eagle Ford wells with longer laterals and wider spacing Further test the Austin Chalk Execute Phase 2 program of joint-venture in North Area 2019 PLAN DETAILS ~28 net drilled; ~18 net completions ~11,570 average lateral feet per well ~1,040 average spacing within zone $6.9MM average well cost ~29% Boe PDP decline (YE18 YE19) YE 2018 INVENTORY: YEARS O p e r a t i n g D e t a i l s Rigs Currently Running: Completion Crews: ~163,000 N E T A C R E S North Area South Area DIMMIT COUNTY WEBB COUNTY East Area 16

17 Well Productivity Midland Basin Boe 20:1/ft MIDLAND BASIN WELL RESULTS SM RANKS #1 IN WELL PRODUCTIVITY IMPROVEMENT (1) 30% W e l l P r o d u c t i v i t y I m p r o v e m e n t Ye a r o v e r Ye a r 20% 10% 0% -10% -20% -30% -40% (1) BMO Capital Markets Research, January Data represents first nine months of 2018 and

18 BUILDING THE RIGHT CULTURE COMMITMENT TO ETHICAL OPERATIONS AND CORE VALUES We are committed to honoring our core values, including conducting our business with ethics and integrity and in compliance with applicable laws and regulations Provide a rewarding and productive work experience for our employees Support the communities where we live, work and operate Conduct business with the highest ethical standard SM ENERGY CORE VALUES Protect the health and safety of our employees, contractors, and neighbors Protect the environment and be a good steward of natural resources 2017 Inaugural CSR report Responsible Stewardship Regularly engage with local community leaders to identify and address key concerns related to our operations Board annually establishes environmental, health and safety (EHS) performance goals, which are reviewed quarterly and impact STIP payout Achieved a 0 Total Recordable Incident Rate (TRIR) for employees per 200,000 man hours in 2017; contractor TRIR was 0.53, lowest level achieved since 2011 Implement a Spill Reduction Planning effort in each region, which generally goes beyond current EPA requirements Disclose information using the GRI Framework Member of the API Environmental Partnership 18

19 Appendix 19

20 Fourth Quarter and Full Year Performance 20

21 4TH QUARTER AND FULL YEAR 2018 PERFORMANCE BIG CASH FLOW GROWTH Production & Pricing 4Q Total Production (MMBoe / MBoe/d) 11.3/ /120.3 Oil Percentage 45% 43% Pre-Hedge Realized Price ($/Boe) $34.74 $37.27 Post-Hedge Realized Price ($/Boe) $31.74 $34.18 Costs $/Boe $/Boe LOE $4.98 $4.74 Ad Valorem $0.39 $0.48 Transportation $4.19 $4.36 Production Taxes $1.19 $1.52 Production Expenses $10.75 $11.10 Cash Production Margin (pre-hedge) $23.99 $26.17 G&A Cash $2.27 $2.23 G&A Non Cash $0.42 $0.42 Operating Margin (pre-hedge) $21.30 $23.52 DD&A $16.10 $15.15 Earnings 4Q EPS (Diluted) $2.73 $4.48 Adjusted EPS (1) $(0.18) $0.03 Adjusted EBITDAX (1) ($MM) $209.2 $900.4 $756.6 MM Discretionary Cash Flow (1) 2018 > 50% increase (2) $23.52 Operating Margin 2018 > 65% increase (2) (1) Discretionary cash flow, Adjusted EPS, and Adjusted EBTIDAX are non-gaap financial measures. See Appendix for reconciliation of these non-gaap measures. (2) 2018 compared to

22 4Q18 REALIZATIONS BY REGION Benchmark Pricing NYMEX WTI Oil ($/Bbl) $58.81 NYMEX LLS Oil ($/Bbl) $66.78 NYMEX Henry Hub Gas ($/MMBtu) $3.64 Hart Composite NGL ($/Bbl) $29.91 Production Volumes Eagle Ford (1) Permian Total Oil (MBbls) 303 4,789 5,091 Gas (MMcf) 18,569 6,910 25,480 NGL (MBbls) 1, ,962 MBoe 5,353 5,947 11,300 Revenue (in thousands) Oil $16,456 $234,488 $250,943 Gas 65,839 28,630 94,468 NGL 46, ,119 Total $129,230 $263,301 $392,531 Expenses (in thousands) LOE $14,150 $42,111 $56,261 Ad Valorem 2,497 1,893 4,390 Transportation 47, Production Taxes ,982 13,468 Per Unit Metrics: Realized Oil per Bbl $54.37 $48.97 $49.29 % of Benchmark - WTI 92% 83% 84% Realized Gas per Mcf $3.55 $4.14 $3.71 % of Benchmark NYMEX HH 98% 114% 102% Realized NGL per Bbl $24.00 nm $24.01 % of Benchmark HART 80% nm 80% Realized per Boe $24.14 $44.28 $34.74 Simplified Portfolio: 2 Top Tier Areas of Operation $34.69 Permian Production Margin LOE per Boe $2.64 $7.08 $4.98 Transportation per Boe $8.83 $0.01 $4.19 Ad Val per Boe $0.47 $0.32 $0.39 Production Tax - per BOE/% of Pre-Hedge Revenue $0.09/0.4% $2.18/4.9% $1.19/3.4% Production Margin per Boe $12.11 $34.69 $23.99 Note: Totals may not calculate due to rounding and other classifications. (1) Includes nominal amounts of other production and expenses from the region. 22

23 2018 PROVED RESERVES BY REGION YE 2017 (1) (MMBoe) YE 2018 South Texas Permian Total Oil (MMBbl) Gas (Bcf) ,321.8 NGL (MMBbl) Total (MMBoe) % Proved Developed 55% 40% 49% Reserve growth 7% 37% 18% 1) Adjusted to show retained assets only 23

24 2018 ACTIVITY BY REGION WELLS DRILLED, FLOWING COMPLETIONS, AND DUC COUNT Wells Drilled Flowing Completions DUC Count 4 th Quarter YTD 4 th Quarter YTD As of December 31, 2018 Region Gross Net Gross Net Gross Net Gross Net Gross Net Permian Sweetie Peck RockStar Permian total Eagle Ford (1) Subtotal Operated Wells Non-operated Wells (2) n/a - n/a - n/a - n/a 1 n/a - Total n/a As of December 31, 2018 (1) 2018 YTD net wells were adjusted for JV phase 2 contract terms. During 2018, there were 18 gross JV wells drilled and 16 JV wells completed. As of December 31, 2018, there were 6 gross JV DUCs. (2) Non-operated activity relates to wells located in the Permian Basin. 24

25 LEASEHOLD SUMMARY Region Midland Basin Net Acres (1) 12/31/2018 RockStar 64,870 Sweetie Peck (2) 16,850 Midland Basin Total 81,720 Eagle Ford (3) 162,990 Rocky Mountain Other (4) 173,980 Other Areas/Exploration 26,385 Total 445,075 (1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of December 31, (2) Sweetie Peck acreage includes 1,885 net drill-to-earn acreage. (3) Approximately 1,500 net acres from the area were reclassified to Other Areas/Exploration. (4) Rocky Mountain Other includes non-core Williston Basin, and other non-core acreage located in North Dakota, Montana, Wyoming, and Utah. 25

26 BALANCE SHEET OFFERS FINANCIAL FLEXIBILITY LIQUIDITY OF $1.1B (1) ; NO NEAR-TERM MATURITIES Redeemed $345 million principal outstanding 6.5% senior notes due 2021 Extended ~$480MM in near-term maturities to 2027 Net debt:ttm Adjusted EBITDAX (3) 2.9 times Debt Maturities (2) (in millions) $1,750 $0 drawn Borrowing Base: $1.5B Commitments: $1.0B $1,500 $1,250 $1,000 $750 $ $ $ $ $ $ $ $250 $0 Coupon 1.500% 6.125% 5.000% 5.625% 6.750% 6.625% Yield to worst (2) % 6.01% 6.50% 7.05% 7.04% Initial call date - 11/2018 7/2018 6/2020 9/2021 1/2022 Initial call price % % % % % (1) As of December 31, 2018 (2) Debt maturities as of December 31, 2018; YTW as of February 15, 2019 (3) Net Debt and Adjusted EBITDAX are non-gaap financial measures. See Appendix for definition of Net Debt:TTM (trailing twelve month) Adjusted EBITDAX (non-gaap) and reconciliation of TTM Adjusted EBITDAX to GAAP net income. 26

27 NGL REALIZATIONS SM NGL price realizations are predominantly tied to Mont Belvieu, fee based contracts Differential reflects NGL barrel product mix, transportation and fractionation fees SM Typical NGL Bbl (1) 4Q17 1Q18 2Q18 3Q18 4Q18 Mt. Belvieu ($/Bbl) $32.12 $30.87 $33.10 $37.97 $29.91 SM Realization ($/Bbl) $26.01 $25.53 $27.55 $30.77 $ % 7% 7% 21% 53% % Differential to Mt. Belvieu 81% 83% 83% 81% 80% Ethane Isobutane Natural Gasoline Propane Normal Butane (1) Reflects ethane processing; if the Company elects not to process ethane, the typical NGL barrel would consist of 42% ethane, 27% propane, 13% natural gasoline, 9% normal butane, and 9% isobutane. During 2018, the Company elected to process ethane in May, July, and August through November. During 2019, the Company has elected to process ethane in January and February. 27

28 2019 Plan Activity & Hedges 28

29 Operated Rigs Total Net DUCs 2019 PLANNED RIG ACTIVITY AND COMPLETIONS BY MONTH Completion Crews Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Midland Basin Eagle Ford (1) Midland Basin Eagle Ford Eagle Ford JV Total Net DUCs (1) Excludes 1 completion crew in April and June through August related to the Eagle Ford JV. 29

30 WELL HEDGED PERCENTAGE OF EXPECTED PRODUCTION HEDGED Production Hedged (1) ~70% ~70% of expected 2019 production volumes hedged ~70% oil volumes ~65% gas volumes (NGLs hedged by product) Midland-Cushing Basis Swaps ~60% ~60% of expected Permian oil production covered by basis hedges at ~$3.55/Bbl Note: Hedging data as of February 18, 2019; all percentages calculated using mid-point of guidance. (1) Percentage includes oil swaps and collars, natural gas swaps and collars, and NGL swaps; does not include basis swaps. 30

31 OIL AND GAS DERIVATIVE POSITIONS BY QUARTER THROUGH 2020 Period Midland - Cushing Oil Swaps Oil Collars Oil Basis Swaps Volume Volume (MBbls) $/Bbl (1) (MBbls) Ceiling $/Bbl (1) Floor $/Bbl (1) Volume (MBbls) Price Differential $/Bbl (1) 1Q $ ,503 $64.32 $ ,433 ($4.44) 2Q $ ,802 $64.61 $ ,571 ($4.49) 3Q 19 1,217 $ ,364 $62.67 $ ,291 ($2.86) 4Q 19 1,115 $ ,386 $62.65 $ ,338 ($2.87) 1Q $ $66.47 $ ,388 ($1.00) 2Q $ $66.50 $ ,792 ($1.04) 3Q $ $66.47 $ ,756 ($1.05) 4Q $ $66.43 $ ,665 ($1.05) Period Gas Swaps Volume Volume (BBTU) $/MMBTU (1) (BBTU) Gas Collars Ceiling $/MMBTU (1) Floor $/MMBTU (1) 1Q 19 19,805 $ Q 19 10,439 $2.82 4,358 $2.83 $2.50 3Q 19 12,531 $2.82 5,066 $2.83 $2.50 4Q 19 14,433 $2.88 4,818 $2.83 $2.50 1Q 20 9,123 $ Q Q Q Note: Includes derivative contracts for settlement at any time during the first quarter of 2019 and later periods through 2020, entered into as of 2/18/19. Excludes gas swaps related to volumes settling against IF WAHA and GD WAHA. (1) Prices are weighted averages; natural gas prices reflect the weighted average of regional contract positions and are no longer adjusted to a NYMEX equivalent. 31

32 NGL DERIVATIVE SWAP POSITIONS (1) OPIS MT. BELVIEU Period Ethane Purity Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 3,533 Period Propane Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 2,389 Period Isobutane Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 117 1Q $ Q $ Total 539 Period Natural Gasoline Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 197 Period Normal Butane Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 154 (1) Includes all NGL derivative contracts for settlement at any time during the first quarter of 2019 and later periods, entered into as of 2/18/19. (2) Weighted-Average Contract Price 32

33 Fourth Quarter and Full Year 2018 Non-GAAP Reconciliations & Disclosures 33

34 TOTAL CAPITAL SPEND RECONCILIATION TO COSTS INCURRED (GAAP) Reconciliation of costs incurred in oil and gas activities (GAAP) to total capital spend (non-gaap) (1)(3) (in millions) Three Months Ended December 31, 2018 Twelve Months Ended December 31, 2018 Costs incurred in oil and gas activities (GAAP): $280.7 $1,389.5 Less: Asset retirement obligations (4.2) (6.8) Capitalized interest (4.9) (20.6) Proved property acquisitions (2) (1.3) (1.3) Unproved property acquisitions (7.7) (32.3) Other (1.6) 0.6 Total capital spend (non-gaap): $261.0 $1,329.1 Note: Amounts may not calculate due to rounding (1) The non-gaap measure of total capital spend is presented because management believes it provides useful information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that total capital spend is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Total capital spend should not be considered in isolation or as a substitute for Costs Incurred or other capital spending measures prepared under GAAP. The total capital spend amounts presented may not be comparable to similarly titled measures of other companies. (2) Includes approximately $0.3 million of ARO associated with proved property acquisitions for the year ended December 31, (3) The Company completed several primarily non-monetary acreage trades in the Midland Basin during 2018 totaling $95.1 million of value attributed to the properties surrendered. This non-monetary consideration is not reflected in the costs incurred or capital spend amounts presented above. 34

35 ADJUSTED EBITDAX (1) RECONCILIATION TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP) Reconciliation of net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-gaap): (in thousands) Three Months Ended December 31, 2018 Twelve Months Ended December 31, 2018 Net income (GAAP) $309,732 $508,407 Interest expense 38, ,906 Interest income (596) (5,191) Income tax expense 82, ,370 Depletion, depreciation, amortization, and asset retirement obligation liability accretion 181, ,313 Exploration (2) 12,859 49,627 Abandonment and impairment of unproved properties 23,274 49,889 Stock-based compensation expense 6,228 23,908 Net derivative gain (411,136) (161,832) Derivative settlement loss (33,892) (135,803) Net gain on divestiture activity (1,261) (426,917) Loss on extinguishment of debt 18 26,740 Other 1,901 1,977 Adjusted EBITDAX (non-gaap) $209,181 $900,394 Interest expense (38,056) (160,906) Interest income 596 5,191 Income tax expense (82,028) (143,370) Exploration (2) (12,859) (49,627) Amortization of debt discount and deferred financing costs 3,716 15,258 Deferred income taxes 81, ,708 Other, net 470 (1,690) Net change in working capital 17,396 13,671 Net cash provided by operating activities (GAAP) $179,452 $720,629 1) Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-gaap measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default. 2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the statements of operations for the component of stock-based compensation expense recorded to exploration expense. 35

36 ADJUSTED NET INCOME (LOSS) (1) RECONCILIATION TO NET INCOME (GAAP) Reconciliation of net income (GAAP) to adjusted net income (loss) (non-gaap): (in thousands, except per share data) Three Months Ended December 31, 2018 Twelve Months Ended December 31, 2018 Net income (GAAP) $309,732 $508,407 Net derivative gain (411,136) (161,832) Derivative settlement loss (33,892) (135,803) Net gain on divestiture activity (1,261) (426,917) Abandonment and impairment of unproved properties 23,274 49,889 Loss on extinguishment of debt 18 26,740 Other, net 1,901 2,777 Tax effect of adjustments (2) 91, ,997 Adjusted net income (loss) (non-gaap) $(19,986) $3,258 Net income per diluted common share (GAAP) $2.73 $4.48 Net derivative gain (3.63) (1.43) Derivative settlement loss (0.30) (1.20) Net gain on divestiture activity (0.01) (3.76) Abandonment and impairment of unproved properties Loss on extinguishment of debt Other, net Tax effect of adjustments (2) Adjusted net income (loss) per diluted common share (non-gaap) $(0.18) $0.03 Diluted weighted-average common shares outstanding (GAAP): 113, ,502 Note: Amounts may not calculate due to rounding 1) Adjusted net income (loss) excludes certain items that the Company believes affect the comparability of operating results. Items excluded generally are non-recurring items or are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as derivative gains and losses net of settlements, impairments, net (gain) loss on divestiture activity, materials inventory loss, and gains or losses on extinguishment of debt. The non-gaap measure of adjusted net income (loss) is presented because management believes it provides useful additional information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that adjusted net income (loss) is widely used by professional research analysts and others as a performance measure in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted net income (loss) should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, cash provided by operating activities, or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income (loss) excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted net income (loss) amounts presented may not be comparable to similarly titled measures of other companies. 2) The tax effect of adjustments is calculated using a tax rate of 21.7%, for the three-month and twelve-month periods ended December, Note that the rate used for the three-month period ended March 31, 2018 was 21.9%. This rate approximates the Company's statutory tax rate adjusted for ordinary permanent differences. 36

37 DISCRETIONARY CASH FLOW RECONCILIATION TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP) Reconciliation of net cash provided by operating activities (GAAP) to discretionary cash flow (non-gaap) (1) (in millions) Three Months Ended December 31, 2018 Twelve Months Ended December 31, 2018 Net cash provided by operating activities (GAAP): $179.5 $720.6 Net change in working capital (17.4) (13.7) Exploration (2)(3) Discretionary cash flow (non-gaap): $175.0 $756.5 Note: Amounts may not calculate due to rounding (1) Discretionary cash flow is defined as net cash provided by operating activities excluding changes in assets and liabilities, and exploration (included in our capital spend guidance). Discretionary cash flow is widely accepted as a financial indicator of an oil and gas company s ability to generate cash which is used to internally fund exploration and development activities, pay dividends, and service debt. Discretionary cash flow is presented because management believes it provides useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities, or have different financing and capital structures or tax rates. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income. (2) Exploration expense is added back in the calculation of discretionary cash flow because, for peer comparison purposes, this number is included in our reported total capital spend. (3) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the statements of operations for the component of stock-based compensation expense recorded to exploration expense. 37

38 PV-10 RECONCILIATION TO STANDARDIZED MEASURE (GAAP) Reconciliation of standardized measure (GAAP) to PV-10 (non-gaap) (1) (in millions) As of December 31, 2018 As of December 31, 2017 Standardized measure of discounted future net cash flows (GAAP): $4,654.4 $3,024.1 Add: 10 percent annual discount, net of income taxes 3, ,573.2 Add: future undiscounted income taxes 1, Undiscounted future net cash flows 9, ,803.0 Less: 10 percent annual discount without tax effect (4,409.4) (2,746.5) PV-10 (non-gaap): $5,104.3 $3,056.5 PV-10 value of assets sold in 2018: n/a (207.3) PV-10 pro-forma assets sold: $5,104.3 $2,849.2 (1) The non-gaap measure of PV-10 is presented because management believes it provides useful information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that PV-10 is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. PV-10 should not be considered in isolation or as a substitute for other measures prepared under GAAP. 38

39 DEFINITIONS AND RECONCILIATION OF NET DEBT : TTM ADJUSTED EBITDAX The Company defines Net debt as the total principal value of outstanding senior notes, senior convertible notes plus balances drawn on the revolving credit facility (also referred to as total funded debt) less cash and cash equivalents. The Company presents this metric to help evaluate its capital structure and financial leverage and believes that it is widely used by professional research analysts, including credit analysts, and others in the evaluation of total leverage. Reconciliation of Net Debt (in thousands) December 31, 2018 Senior Notes (principal value from Note 5 of Form 10-K) $ 2,476,796 Senior Convertible Notes (principal value from Note 5 of Form 10-K) 172,500 Revolving credit facility Total funded debt $ 2,649,296 Less: Cash and cash equivalents (77,965) Net Debt $ 2,571,331 The Company defines Net debt-to-adjusted EBITDAX as Net Debt (defined above) divided by adjusted EBITDAX (reconciled on previous slide) for the prior twelve-month period. The Company presents this metric to show trends that investors may find useful in understanding the Company s ability to service its debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. A variation of this calculation is a financial covenant under the Company s credit agreement for its revolving credit facility beginning in the fourth quarter of

40 DEFINITION OF TOTAL CAPITAL SPEND The Company defines Total capital spend as costs incurred, less ARO, capitalized interest and acquisitions. Total capital spend is presented because management believes that it provides useful information to investors in the analysis of SM Energy and is widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry. Total capital spend should not be used in isolation or as a substitute to costs incurred or other capital spending measures under GAAP. Total capital spend may not be comparable to similarly titled measures of other companies. We are unable to provide a reconciliation of this forward-looking non-gaap measure to the most comparable GAAP financial measure because certain information needed to reconcile this measure is dependent on future events, some of which are outside of the control of the Company. Moreover, estimating such GAAP measures with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. Capital spend as reported for actual results is reconciled above to GAAP costs incurred in oil and gas activities. 40

41 RESERVES AND RESOURCES The Securities and Exchange Commission ( SEC ) requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions (using the trailing 12-month average first-day-of-the-month prices), operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, the Company currently does not disclose probable or possible reserves in its SEC filings. In this presentation, proved reserves attributable to the Company at December 31, 2018, are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $65.56 per Bbl of oil, $3.10 per MMBtu of natural gas, and $33.45 per Bbl of NGLs. At least 80% of the PV-10 of the Company s estimate of its total proved reserves at December 31, 2018, was audited by Ryder Scott Company, L.P. The Company may use the terms economic resource, economic inventory, additional resource and similar phrases to describe estimates of gross drilling locations that the SEC rules may prohibit from being included in filings with the SEC. These are the Company s internal estimates of drilling locations. These quantities may not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or SEC rules. Such estimates and identified drilling locations may not have been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company s interests could differ substantially from these estimates. There is no commitment by the Company to drill all of these drilling locations. The calculation of economic resources is not necessarily calculated in accordance with SEC guidelines for proved reserves and is not reviewed by third party engineers. Economic resources presented in this presentation are calculated using benchmark pricing and projected pricing, which differs from the pricing used for proved reserves. Management believes the presentation of economic resources and economic drilling inventory are useful to investors in the valuation of SM Energy; however, the calculations may not be consistent with similar metrics provided by peers. 41

42 CONTACT INFORMATION Jennifer Martin Samuels Vice President - Investor Relations jsamuels@sm-energy.com 42