Operating Results APRIL 29, 2020 SM-ENERGY.COM DISCLAIMERS - PowerPoint PPT Presentation

1Q 2020 Financial & Operating Results APRIL 29, 2020 SM-ENERGY.COM

DISCLAIMERS Forward-looking statements This presentation contains forward-looking statements within the meaning of securities laws. The words "assumes," "anticipate," "estimate," "expect," "forecast, "generate," "guidance," "implied," "plan," "project," "objectives," "outlook," "sustainable," "target," "trajectory," "will" and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this release include, among other things, guidance for the full year and second quarter 2020, including production volumes, oil production growth, operating and general and administrative costs, DD&A, capital expenditures, average lateral feet per well, average well costs, year-over-year PDP decline, and number of rigs and completions crews expected to be running through YE 2020; the Company’s 2020 strategic priorities, including: improved operating margins and cash flow, oil mix as a percentage of producti on, delivery of free cash flow, and increasing inventory and inventory value; the Company’s 2020 goals, including: reducing leverage and generating full -year 2020 free cash flow; and the number of wells the Company plans to drill and complete. 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. Future results may be impacted by the risks discussed in the Risk Factors section of SM Energy's most recent Annual Report on Form 10-K and Q1 2020 Form 10-Q, 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 release. 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 This presentation references non- GAAP financial measures. Please see the “Non - GAAP Definitions and Reconciliations” section of t he Appendix, which includes definitions of non-GAAP measures used and reconciliations to the directly most directly comparable GAAP measure. 2

PREMIER OPERATOR OF TOP-TIER ASSETS STRONG FIRST QUARTER AND SCALED-BACK 2020 CAPITAL P R O D U C T I O N ▪ Production of 12.4 MMBoe (135.9 MBoe/d) and 51% oil at high-end of guidance ~$81 MM F R E E C A S H F L O W ▪ Generated $81MM of free cash flow (1) FREE CASH FLOW (1) A B S O L U T E D E B T R E D U C T I O N ▪ $41MM market purchases of 2022 bonds for $28.3MM ▪ $50MM reduction in credit facility balance ▪ Net Debt-to-Adjusted EBITDAX at 2.45x (1) B O R R O W I N G B A S E R E D E T E R M I N AT I O N C O M P L E T E D ~$91 MM ▪ Borrowing Base redetermined at $1.1B with Commitments of $1.1B C A P I TA L P R O G R A M R E D U C E D A N D R E M A I N S F L E X I B L E DEBT REDUCTION ▪ Capital expenditures reduced ~20% Free cash flow and net debt-to-adjusted EBITDAX are non- GAAP financial measures. See “Definitions of non -GAAP measures as (1) Calculated by the Company” and related reconciliations in the Appendix. Net debt -to-Adjusted EBITDAX as of March 31, 2020.. 3

FIRST QUARTER 2020 PERFORMANCE Key y Metrics rics Q1 2020 Production Production and Pricing Total Production (MMBoe) 12.4 135.9 Total Production (MBoe/d) 135.9 Oil percentage 51% MBoe/d Pre-Hedge Realized Price ($/Boe) $28.64 Post-Hedge Realized Price ($/Boe) $34.58 Costs (per Boe) LOE $4.75 Transportation $3.11 Production & Ad Valorem taxes $1.80 Adjusted EBITDAX (1) Total Production Expenses $9.67 Cash Production Margin (pre-hedge) $18.97 $286 G&A (Cash) $1.85 G&A (Non-Cash) $0.37 million Operating Margin (pre-hedge) $16.76 DD&A $18.88 Earnings GAAP net loss (per share) ($3.64) Adjusted net loss (1) (per share) ($0.05) Adjusted EBITDAX (1) ($MM) $286.0 Free Cash Flow (1) Free Cash Flow ($MM) Net cash provided by operating activities (GAAP) $218.1 Net change in working capital (GAAP) $18.5 $81 Net cash provided by operating activities before net change in working capital $236.6 million Less: Capital Expenditures (GAAP) $139.9 Increase in capital expenditure accruals and other (GAAP) $16.8 Free Cash Flow (1) $80.5 Note: Amounts may not sum due to rounding. Adjusted net loss, Adjusted EBITDAX, and Free Cash Flow are non- GAAP financial measures. See the “Non -GAAP Definitions and Recon ciliations” section in the Appendix. 4 (1)

BALANCE SHEET FOCUS LEVERAGE METRICS IMPROVED Debt Maturities ( 1 ) in millions $1.1B 1B $1,250 Commitments & Borrowing Base $1,000 Liquidity of $1B (2) $750 Borrowing base re-determined in April 2020 $500 (3) Net debt-to-Adjusted EBITDAX $500 $500 $500 $500 $250 $436.0 2.45x $72 $172.5 $0 2020 2021 2022 2023 2024 2025 2026 2027 Coupon 1.500% 6.125% 5.000% 5.625% 6.750% 6.625% Initial Call Date 11/2018 7/2018 6/2020 9/2021 1/2022 102.81% Initial Call Price 103.06% 102.50% 103.38% 104.97% Maturity Date 7/2021 11/2022 01/2024 06/2025 09/2026 01/2027 (1) As of March 31, 2020; Commitments and Borrowing Base as of April 29, 2020. Pro- forma for the Company’s senior secured revolving credit facility borrowing base redetermination which was completed on April 29, 2020. (2) Net debt-to-Adjusted EBITDAX is a non- GAAP measure. See the “Non - GAAP Definitions and Reconciliations” section in the Appendix. (3) 5

HEDGING SUMMARY STRONG HEDGE PROTECTION AT CURRENT OIL PRICES 2Q – 4Q 2020 Oil Volumes Hedged (1) ~14,340 MBbls 2020 Hedge dge Pro rogra ram ▪ ~14,340 MBbls (1) of 2Q – 4Q oil production hedged to WTI; At prices > $55/Bbl swaps at ~$57/Bbl, collar floors at $55/Bbl ▪ Midland Basin oil production for the remainder of 2020 is substantially hedged at basis Midland to Cushing ▪ ~28,985 BBtu (2) of 2Q – 4Q natural gas production hedged ▪ NGLs hedged by product 2Q – 4Q 2020 oil hedges include oil swaps and collars to WTI only; excludes basis swaps. (1) 2Q – 4Q 2020 natural gas hedges include IF HSC and WAHA gas swaps. (2) 6

MIDLAND BASIN TOP-TIER EXECUTION, WELL PERFORMANCE AND CAPITAL EFFICIENCY 2 0 2 0 P L A N O B J E C T I V E S 2 0 2 0 R E V I S E D P L A N HOWARD ▪ ~11,300’ expected average lateral feet per well ▪ ~$6.8MM expected average well cost RockS ckStar tar ▪ ~48% Boe PDP decline (YE19 - YE20) MARTIN B E S T I N C L A S S W E L L P E R F O R M A N C E ▪ SM wells generate among the highest revenues per well in the Midland Basin (1) ▪ JP Morgan Equity Research: “We believe that western Howard County is one of the most prolific/economic areas in the Midland Basin.” (2) L E A D I N G E D G E C A P I T A L C O S T S ▪ Expected DC&E costs further reduced to ~$600/lateral foot (3) O P E R AT I N G D E TA I L S Sweet eetie e Peck ck ~ 82,000 Completion Rigs Running: Crews: MIDLAND N E T A C R E S UPTON (1) Baird Equity Research, Joseph Allman, November 4, 2019; Baird Energy Big Data Analytics (May 2018 - April 2019 first production). (2) J.P. Morgan Equity Research, Michael Glick, February 19, 2020; SM Energy 4Q:19 Flash: Huge 4Q, 1Q Guide. (3) As of April 30, 2020. 7

MIDLAND BASIN: TOP-TIER CAPITAL EFFICIENCY LEADING DC&E COSTS REDUCED TO ~$600 PER LATERAL FOOT Longer Laterals Drilling and Completion Efficiency Gains Average Lateral Length Completed (2) 22% Drilled and completed feet per day (1) 11,300 INCREASE IN LATERAL LENGTH 53% 9,300 778 DRILLING IMPROVEMENT 645 562 2017 2018 2019 2020 510 REVISED PLAN Lower Sand Costs 2017 2018 2019 Q1'20 Indexed to January 2019 (3) 127% 1,740 43% 1,503 COMPLETION IMPROVEMENT LOWER SAND COSTS 1.0 1,025 765 0.6 2017 2018 2019 Q1'20 (1) Drilling: total lateral feet delivered per day, spud to rig release. Completion: lateral feet completed per fleet per day. (2) 2020 Plan lateral length average subject to change. Jan. Apr. July Oct. Jan. Mar. (3) Sand costs exclude last mile logistics as there is variability in these charges. '19 '19 '19 '19 '20 '20 8

SOUTH TEXAS FOCUSED ON EXECUTION AND RETURNS ENHANCEMENT 2 0 2 0 P L A N O B J E C T I V E S 2 0 2 0 R E V I S E D P L A N ▪ ~11,700’ expected average lateral feet per well ▪ ~$7.25MM expected average well cost / DC&E costs further reduced to DIMMIT COUNTY ~$620/lateral foot WEBB COUNTY ▪ ~27% Boe PDP decline (YE19 - YE20) A U S T I N C H A L K S U C C E S S North Area ▪ Briscoe G 109H, completed in the fourth quarter of 2020, continues to outperform expectations East Area (1) O P E R AT I N G D E TA I L S South Area ~159,000 Rigs Running: N E T A C R E S (1) As of April 30, 2020. 9