SM-ENERGY.COM

STEPHENS ANNUAL INVESTMENT CONFERENCE

NOVEMBER 18, 2020

2

DISCLAIMERS

Forward-looking statements

Non-GAAP financial measuresThis presentation references non-GAAP financial measures. Please see the “Non-GAAP Definitions and Reconciliations” section of the Appendix, which includes definitions of non-GAAP measures

used in this presentation and reconciliations to the most directly comparable GAAP measure.

This presentation contains forward-looking statements within the meaning of securities laws. The words “assumes,” “anticipate,” “estimate,” “expect,” “forecast,” “generate,” “guidance,” “implied,”

“maintain,” “plan,” “project,” “objectives,” “outlook,” “sustainable,” “target,” “will” and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this

release include, among other things, 2020 capital expenditure guidance, Austin Chalk inventory additions, commodity mix of our expected future production, bringing drilled but uncompleted wells

onto production, per-well costs, expected future production margins, expected future condensate realizations and transportation costs; the Company’s 2020 goals, including: generating free cash

flow, ESG performance, reduced leverage; 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, 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,

specifically the third quarter 2020 Form 10-Q. The forward-looking statements contained herein speak as of the date of this presentation. 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.

3

PREMIER OPERATOR OF TOP-TIER ASSETSFOCUSED ON TWO BASINS IN TEXAS

MIDLAND BASIN

▪ ~82,000 net acres

▪ 3 Rigs / 2 Completion Crews

SOUTH TEXAS

▪ ~159,000 net acres

▪ 1 Rig / 1 Completion Crew

ENTERPRISE VALUE: ~$2.7 Billion(1)

PRODUCTION: ~126.36 MBoe/d; 47% oil (3Q20)

PROVED RESERVES:462 MMBoe (YE 2019)

2020 CAPEX GUIDANCE:$590 - $595MM(2)

(1) As of November 16, 2020.

(2) As of November 16, 2020, includes adjustment for South Texas third party agreement to fund the majority of completion costs for six wells; CAPEX calculated as capital expenditures before changes in capital expenditure accruals.

4

Cash Flow Growth

PREMIER OPERATOR OF TOP-TIER ASSETSCHALLENGING TIMES, BUT OUR PRIORITIES HAVE NOT CHANGED

P R I O R I T I E ST A R G E T S

▪ Growth within cash flow

▪ Net debt-to-Adjusted EBITDAX(1) at <2x

▪ Premier ESG performer

Free Cash Flow Funded

Debt Reduction

V A L U E C R E A T I O NImprove Leverage

MetricsCash Flow Growth per Debt Adjusted Share

+

+

(1) Net debt-to-Adjusted EBITDAX are non-GAAP financial measures. See “Definitions of non-GAAP measures as Calculated by the Company” and related reconciliations in the Appendix.

5

~$172MMYTD FREE CASH FLOW(1)

F R E E C A S H F L O W

P R O D U C T I O N

A B S O L U T E D E B T R E D U C T I O N

C A P I T A L G U I D A N C E R E D U C E D

~$106MM3Q PRINCIPAL REDUCTION IN LT DEBT

STRONG THIRD QUARTER RESULTED IN SIGNIFICANT FCF & ABSOLUTE DEBT REDUCTION

PREMIER OPERATOR OF TOP-TIER ASSETS

▪ Generated ~$64 million of free cash flow (1) in 3Q and

~$172MM during first nine months of 2020

▪ 3Q Production of 11.6 MMBoe (126.3 MBoe/d) and 47% oil

▪ 3Q: ~$91MM market purchases of 2022 and 2024

bonds for ~$66MM

▪ Net debt-to-Adjusted EBITDAX at 2.4x(1) as of

September 30, 2020

(1) Free cash flow & net debt-to-Adjusted EBITDAX are non-GAAP financial measures. See “Definitions of non-GAAP measures as Calculated by the Company” and related reconciliations in the Appendix.

▪ 2020 capital expenditures further reduced from July update;

reduced ~27% from February plan

E S G F O C U S

▪ Published updated Corporate Responsibility Report, 2019

Sustainability Accounting Standards metrics for oil and gas

E&P companies, as well as certain ESG metrics relevant to

understanding the Company’s 2019 ESG performance

THIRD QUARTER 2020 PERFORMANCE

6

Adjusted EBITDAX(1)

$233

Production

126.3

Free Cash Flow(1)

$64

MBoe/d

million

million

Key Metrics

(1) Adjusted net loss, Adjusted EBITDAX, and Free Cash Flow are non-GAAP financial measures. See the “Non-GAAP Definitions and Reconciliations” section in the Appendix.

Note: Amounts may not sum due to rounding.

Q3 2020Production and Pricing

Total Production (MMBoe) 11.6

Total Production (MBoe/d) 126.3

Oil percentage 47%

Pre-Hedge Realized Price ($/Boe) $24.28

Post-Hedge Realized Price ($/Boe) $30.33

Costs (per Boe)

LOE $3.65

Transportation $3.11

Production & Ad Valorem taxes $1.44

Total Production Expenses $8.20

Cash Production Margin (pre-hedge) $16.08

G&A (Cash) $1.80

G&A (Non-Cash) $0.30

Operating Margin (pre-hedge) $13.98

DD&A $15.64

Earnings

GAAP Earnings (per share) ($0.86)

Adjusted net loss(1) (per share) ($0.05)

Adjusted EBITDAX(1) ($MM) $232.5

Free Cash Flow ($MM)

Net cash provided by operating activities (GAAP) $201.6

Net change in working capital $(16.8)

Net cash provided by operating activities before net change in working capital $184.8

Capital Expenditures (GAAP) $109.6

Increase in capital expenditure accruals and other $11.5

Capital expenditures before increase in capital expenditure accruals and other $121.1

Free Cash Flow(1) $63.7

20252024

1.500%

$65.5

BALANCE SHEET FOCUSLIQUIDITY OF ~$880 MILLION(1), Net debt-to-Adjusted EBITDAX(2) at 2.4x(3)

7

$1,250

$1,000

$750

$500

$250

$0202720262023202220212020

7/2021 11/2022

103.06%

11/2018

6.125% 5.000%

7/2018

102.50%

01/2024

10.000%

5.625%

6/2020

102.81%

01/2025

06/2025

6.750%

9/2021

103.38%

09/2026

6.625%

1/2022

104.97%

01/2027

$419 $417$178$316$232 $349

$447

Second Lien Secured

$500

(1) Liquidity as of September 30, 2020 was $880 million.

(2) Net debt-to-Adjusted EBITDAX is a non-GAAP measure. See the “Non-GAAP Definitions and Reconciliations” section in the Appendix. Bank covenant on revolver is 4x.

(3) As of September 30, 2020.

(4) Borrowing base and Commitments are subject to certain covenants if 2L debt capacity is used to redeem unsecured debt.

$1.1BBorrowing Base

& Commitments

Coupon

Initial Call Date

Initial Call Price

Maturity Date

2.8

2.4

YE19 3Q20 YE20e YE21e

Less than 3x

Less than 3x

Expect to Maintain Net debt-to-Adjusted EBITDAX(2) through 2021 at

<3x

D e b t Matur i t i e s ( 3 )

in millions

3Q Principal Debt Reduction ~$106 million

Net debt-to-Adjusted EBITDAX (2)

▪ Borrowing Base and Commitments $1.1 billion,

unchanged(4)

▪ Second-lien debt capacity retained at ~$380 million

Fall 2020 Redetermination Update:

4Q20 Oil Volumes Hedged(1)

At prices > $55/Bbl

SM Energy Hedge Program

▪ ~5,005 MBbls(1), or approximately 90%+(1) of expected 4Q20 oil production, hedged to

WTI; swaps at ~$57/Bbl, collar floors at $55/Bbl

- ~17,985 MBbls(1) of oil hedged in 2021 to WTI; swaps at ~$40/Bbl, collar floors at

~$49/Bbl

▪ ~4,090 MBbls of 4Q20 Midland Basin oil covered by Midland to Cushing basis hedges at

~$(0.38)/Bbl

- ~13,975 MBbls of 2021 Midland Basin oil covered by Midland to Cushing basis

hedges at ~$0.75/Bbl

▪ ~9,330 BBtu of natural gas hedged in 4Q20 to HSC at an average price of ~$2.39/MMBtu,

and ~4,870 BBtu of Midland Basin natural gas hedged in 4Q20 to WAHA at an average

price of ~$1.21/MMBtu

- ~49,100 BBtu of natural gas hedged in 2021 to HSC at an average price of

~$2.43/MMBtu, and ~26,080 BBtu Midland Basin natural gas hedged in 2021 to

WAHA at an average price of ~$1.70/MMBtu

8

STRONG HEDGE PROTECTION

HEDGING SUMMARY

(1) Hedges include oil swaps and collars to WTI only; excludes basis swaps and roll differential hedges.

~90%+Oil

Natural gas

2021 Oil Volumes Hedged(1)

~18,000 MBblsAt prices > ~$40/Bbl

TOP-TIER EXECUTION, WELL PERFORMANCE AND CAPITAL EFFICIENCY

MIDLAND BASIN

9

MARTIN

RockStarHOWARD

UPTON

Sweetie Peck

MIDLAND

2 0 2 0 P L A N O B J E C T I V E S

O P E R AT I N G D E TA I L S(2)

~82,000

Rigs

Running:

Completion

Crews:

N E T A C R E S(1) RSEG / Enervus research, July 2020.

(2) As of October 29, 2020.

ECTORGLASSCOCK

REAGAN

ANDREWS

C O M P L E T I O N S E X E C U T I O N▪ ~70 net completions planned for 2020

▪ 22 net completions in 3Q20; 50 net completions YTD

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▪ RSEG/Enverus research: SM had the lowest breakeven prices in 2019(1)

T O P - T I E R C A P I T A L E F F I C I E N C Y▪ Drilling and completing wells faster, longer laterals, lower sand costs

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 ≤$560/lateral foot

765

1,025

1,503

2,028

2017 2018 2019 YTD20

1.0

0.5

Jan. '19 Apr. '19 July '19 Oct. '19 Jan. '20 June '20 Sept. '20

10

LEADING DC&E COSTS CURRENTLY AT ≤$560 PER LATERAL FOOT

MIDLAND BASIN: TOP-TIER CAPITAL EFFICIENCY

Drilling and Completion Efficiency Gains Drilled and completed feet per day(1)

51%DRILLING IMPROVEMENT

165%COMPLETION IMPROVEMENT

Longer LateralsAverage Lateral Length Completed(2)

Lower Sand CostsIndexed to January 2019(3)

9,300

11,500

2017 2018 2019 2020 PLAN

24%INCREASE IN LATERAL LENGTH

49%LOWER SAND COSTS

(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.

(3) Sand costs exclude last mile logistics as there is variability in these charges.

510

562

645

772

2017 2018 2019 YTD20

SM Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8

MIDLAND BASIN: SM ENERGY BREAKEVEN BEST IN THE BASIN

11

GREAT ROCK AND LOW COSTS DRIVE STRONG ECONOMICS RELATIVE TO PEERS

(1) RSEG/Enverus Research, July 2020; peers include FANG, CXO, PXD, OVV, CPE, PE, LPI, QEP.

RSEG/Enverus Midland Data: Operator Benchmarking(1)

2019 PV-10 Breakeven Price ▪ According to RSEG/Enverus

research, SM Energy ranked #1

for the lowest breakeven price in

the Midland Basin during 2019(1)

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FOCUSED ON EXECUTION AND RETURNS ENHANCEMENT

SOUTH TEXAS

DIMMIT COUNTY

WEBB COUNTY

North

Area

South Area

East

Area

2 0 2 0 P L A N O B J E C T I V E S

O P E R AT I N G D E TA I L S (1)

~159,000N E T A C R E S

C O M P L E T I O N S E X E C U T I O N▪ Expect ~12 net wells drilled and ~4 net wells completed for the year; 7 net wells drilled

and 4 net wells completed through 3Q

▪ Expected DC&E costs further reduced to ~$600/lateral foot for 2H20

T H I R D P A R T Y A G R E E M E N T▪ The Company has entered into an agreement with a third party to fund the majority of

completion costs for six wells; includes co-development of three lower Eagle Ford and

three Austin Chalk wells currently in the Company’s DUC inventory

M A R K E T I N G U P D A T E▪ Transportation costs expected to decrease ~$0.25/Mcf starting mid-year 2021 and

decrease an additional ~$0.35/Mcf in 2023

▪ Condensate prices expected to improve by ~$5/Bbl relative to prior contract terms

starting 4Q20

A U S T I N C H A L K S U C C E S S▪ Continued optimization of Austin Chalk landing zone and completion design has led to

outstanding performance for latest wells

▪ Delineation program of 9 wells has projected Austin Chalk inventory over a broad area

E N H A N C I N G I N V E N T O R Y VA L U E

Rigs

Running:

(1) As of October 29, 2020.

Completion

Crews:

0

100

200

300

400

500

600

0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300

13

OUTSTANDING PERFORMANCE FROM RECENT AUSTIN CHALK DELINEATION WELLS

SOUTH TEXAS: AUSTIN CHALK SUCCESS CONTINUES

Oil Production(MBo)

J.P. Morgan Research(2): These wells are tracking roughly in-line

with an average Permian well from 2018-2020... If SM could replicate its

2019 well performance going forward, it would be a tailwind to our

2021+ oil production.

Total Production (MBoe; 3-stream)

▪ Latest three Austin Chalk wells have a breakeven flat

oil price range of $17 - $31/Bbl NYMEX(1) at go

forward development capital

▪ Outstanding new wells:

▪ Positive results across acreage position support

expected increase in South Texas inventory

▪ New wells producing 49-54 degree API oil/condensate

1009H 109H

910H

1009H

109H1009H

(1) Breakeven 10% IRR assumes natural gas at $2.00/Mcf through 1H21, then $2.40/Mcf.

(2) J.P. Morgan E&P Shale Well Watcher, Arun Jayaram, October 19, 2020.

910H

109H

Well

Lateral

Length

IP30 Oil

(Bo/d)

IP30

3-stream (Boe/d) Oil % Liquids %

Briscoe G 109H 6,502’ 1,582 2,681 59 80

San Ambrosia D (SA4) 1009H 13,322’ 2,073 3,597 58 80

Galvan Ranch B910H 12,202’ 1,145 3,787 30 59

910H

Days on Production

Cu

mu

lati

ve

Pro

du

cti

on

RSEG/Enverus Research(3): SM’s initial Austin Chalk wells are

producing at encouraging rates and achieve stronger netbacks… It’s too

early to determine the geographic extent and ultimate recoveries of the

formation on SM’s acreage, but assuming the zone performs in line with

SM's latest wells would increase our NAV ~60%.

(3) RSEG / Enervus research, October 18, 2020.

14

HIGH LIQUIDS CONTENT + IMPROVING ECONOMICS EXPECTED TO DRIVE BETTER RETURNS

SOUTH TEXAS: AUSTIN CHALK DRIVING VALUE CREATION

(1) Austin Chalk 1Q22e and 3Q23e expected production margins calculated using South Texas 1Q20 benchmark pricing of $46.17/Bbl oil, $1.95/Mcf gas, $17.02/Bbl NGLs, and 1Q20 South Texas production costs, adjusted to reflect Austin Chalk liquids content and improved economics.

(2) Relative to prior contract terms.

Austin Chalk vs. Current South Texas Margin

South Texas1Q20

Austin Chalk1Q22e

Austin Chalk3Q23e

▪ ~$5/Bbl increase in condensate prices(2) starting 4Q20

▪ ~$0.25/Mcf decrease in transportation costs in 2021

▪ ~$0.35/Mcf decrease in transportation costs in 2023

Comparison at 1Q20 benchmark pricing(1)

South Texas production benefits from higher condensate realizations & lower transportation costs beginning in 2021

$3.04/Boe

~$14/Boe

~$16/Boe

ESG Committee of Board of Directors named in July 2020

Board composition includes: independent

chairman; 8 of 10 independent directors;

diversity of gender, race, geography, tenure

and expertise

15

MAKING PEOPLE’S LIVES BETTER BY RESPONSIBLY PRODUCING OIL & NATURAL GAS

ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG)

2019 TRIR: 0.462020 compensation tied to targeted

top-quartile(1) safety metrics

$1.5 million in 2019Approximate total of SM charitable contributions

2019 GHG Emissions Intensity

12.4

2019 top quartile(1)

Methane Emissions

0.11%

2019 top-quartile(1)

Spill Volumes

(Bbls spilled / 1,000 Bbls produced)

(% of methane produced):

Intensity (mT(2) CO2e / MBoe):

0.015

2019 Flaring Percentage

Executive compensation aligned with

long-term corporate strategy and

performance measures tied to creation of

stockholder value

CORPORATE RESPONSIBILITY REPORT AVAILABLE AT:

SM-ENERGY.COM

1.3%(% of gas flared to total production):

Board has annually established top-quartile(1)

EHS performance goals, which are reviewed

quarterly and impact compensation of every

employee(1) Top-quartile based on surveyed and/or publicly available data from American Exploration & Production Council members.

(2) mT = metric tons.

Employee + Contractor

16

Cash Flow Growth

PREMIER OPERATOR OF TOP-TIER ASSETSCHALLENGING TIMES, BUT OUR PRIORITIES HAVE NOT CHANGED

P R I O R I T I E ST A R G E T S

▪ Growth within cash flow

▪ Net debt-to-Adjusted EBITDAX(1) at <2x

▪ Premier ESG performer

Free Cash Flow Funded

Debt Reduction

V A L U E C R E A T I O NImprove Leverage

MetricsCash Flow Growth per Debt Adjusted Share

+

+

(1) Net debt-to-Adjusted EBITDAX are non-GAAP financial measures. See “Definitions of non-GAAP measures as Calculated by the Company” and related reconciliations in the Appendix.

17

Appendix

18

TWO TOP-TIER AREAS OF OPERATION

3Q 2020 REALIZATIONS BY REGION

Midland Basin

South Texas Total

Production Volumes

Oil (MBbls) 5,023 487 5,510

Gas (MMcf) 12,275 13,785 26,060

NGL (MBbls) 9 1,755 1,764

Total (Mboe) 7,077 4,539 11,617

Revenue (in thousands)

Oil $194,547 $13,100 $207,647

Gas $23,304 $26,251 $49,555

NGL $115 $24,695 $24,810

Total $217,966 $64,046 $282,012

Expenses (in thousands)

LOE $34,625 $7,751 $42,376

Ad Valorem $3,141 $1,563 $4,704

Transportation $94 $36,027 $36,121

Production Taxes $10,715 $1,340 $12,055

Per Unit Metrics

Realized Oil Per Bbl $38.73 $26.90 $37.69

% of Benchmark - WTI 95% 66% 92%

Realized Gas per Mcf $1.90 $1.90 $1.90

0 % of Benchmark - NYMEX Henry Hub 96% 96% 96%

Realized NGL per Bbl $13.22 $14.07 $14.07

% of Benchmark - HART 69% 74% 74%

Realized Price per Boe $30.80 $14.11 $24.28

LOE per Boe $4.89 $1.71 $3.65

Ad Valorem per Boe $0.44 $0.34 $0.40

Transportation per Boe $0.01 $7.94 $3.11

Production Tax per Boe $1.51 $0.30 $1.04

Production Tax as % of Pre-hedge Revenue 4.9% 2.1% 4.3%

Production Margin per Boe $23.95 $3.82 $16.08

Benchmark Pricing

NYMEX WTI Oil ($/Bbl) $ 40.93

NYMEX LLS Oil ($/Bbl) $ 42.45

NYMEX Henry Hub Gas ($/MMBtu) $ 1.98

Hart Composite NGL ($/Bbl) $ 19.13

Note: Amounts may not sum due to rounding and other classifications.

19

WELLS DRILLED, FLOWING COMPLETIONS AND DUC COUNT

ACTIVITY BY REGION

Note: Data as of September 30, 2020.

Wells Drilled Flowing Completions DUC Count(1)

3Q20 2020 YTD 3Q20 2020 YTD As of September 30, 2020

Gross Net Gross Net Gross Net Gross Net Gross Net

Midland Basin

Sweetie Peck 7 6 19 16 - - 8 7 17 14

RockStar 16 13 54 49 22 22 46 43 53 49

Midland Basin total 23 19 73 65 22 22 54 50 70 63

South Texas - - 7 7 2 2 4 4 24 24

Total 23 19 80 72 24 24 58 54 94 87

Oil Swaps Oil CollarsMidland - Cushing

Oil Basis Swaps

NYMEX WTI - ICE Brent

Oil Basis Swaps

NYMEX WTI Roll Basis

Swaps

PeriodVolume

(MBbls)$/Bbl(2) Volume

(MBbls)

Ceiling

$/Bbl(2)Floor

$/Bbl(2)Volume

(MBbls)

Price

Differential

$/Bbl(2)

Volume

(MBbls)

Price

Differential

$/Bbl(2)

Volume

(MBbls)

Price

Differential

$/Bbl(2)

Q4 2020 4,397 $57.03 610 $61.90 $55.00 4,087 ($0.38) 920 ($8.01) 2,503 ($1.18)

Q1 2021 3,613 $42.91 551 $51.96 $48.97 3,223 $0.79 900 ($7.86) 1,345 ($0.55)

Q2 2021 4,583 $39.76 - - - 3,354 $0.78 910 ($7.86) 1,543 ($0.42)

Q3 2021 4,494 $39.69 - - - 3,574 $0.74 920 ($7.86) 1,661 ($0.36)

Q4 2021 4,744 $39.85 - - - 3,824 $0.71 920 ($7.86) 1,509 ($0.30)

Q1 2022 988 $43.67 - - - 2,222 $1.15 900 ($7.78) - -

Q2 2022 945 $43.58 - - - 2,374 $1.15 910 ($7.78) - -

Q3 2022 973 $43.55 - - - 2,442 $1.15 920 ($7.78) - -

Q4 2022 978 $43.54 - - - 2,462 $1.15 920 ($7.78) - -

IF HSC Gas Swaps WAHA Gas Swaps

PeriodVolume

(BBtu)$/MMBtu(2) Volume

(BBtu)$/MMBtu(2)

Q4 2020 9,327 $2.39 4,872 $1.21

Q1 2021 11,592 $2.48 5,994 $1.66

Q2 2021 12,511 $2.42 6,402 $1.66

Q3 2021 12,575 $2.40 7,135 $1.78

Q4 2021 12,412 $2.41 6,548 $1.67

Q1 2022 5,395 $2.77 2,334 $2.53

Q2 2022 5,151 $2.33 2,169 $2.00

Q3 2022 5,385 $2.36 2,165 $2.14

Q4 2022 5,188 $2.45 2,147 $2.19

Propane

PeriodVolume

(MBbls)$/Bbl(2)

Q4 2020 466 $22.29

Q1 2021 275 $20.55

Q2 2021 324 $20.58

Q3 2021 336 $20.56

Q4 2021 331 $20.56

20

BY QUARTER

OIL, GAS, AND NGL DERIVATIVE POSITIONS(1)

Oil

Gas NGLs

(1) Includes derivative contracts for settlement at any time during the fourth quarter of 2020 and later periods, entered into as of 10/26/2020.

(2) Weighted-average contract price.

21

NO LEASEHOLD ON FEDERAL LANDS IN THE MIDLAND BASIN OR SOUTH TEXAS

LEASEHOLD SUMMARY

MIDLAND BASIN NET ACRES

~82,000Midland Basin

Sweetie Peck(2) 18,000

RockStar 64,100

Midland Basin total 82,100

South Texas 158,900

Rocky Mountain Other 10,300

Other Areas / Exploration 26,400

Total 277,700

SOUTH TEXAS NET ACRES

~159,000

As of September 30, 2020

Net Acres(1)

(1) Includes developed and undeveloped oil and natural gas leasehold, fee properties, and mineral servitudes held as of September 30, 2020.

(2) Sweetie Peck acreage includes 1,900 net drill-to-earn acreage.

Differential reflects NGL composite barrel product mix as well as transportation and fractionation fees

NGL REALIZATIONS

22

NGL price realizations tied to Mont Belvieu, fee-based contracts

SM NGL Composition40%

29%

13%

9%9%

Ethane

Isobutane

Natural Gasoline

Propane

Normal

Butane

(1) Graphic reflects ethane rejection; if the Company were to process ethane, the typical NGL barrel would consist of 51% ethane, 23% propane, 12% natural gasoline, 7% normal butane, and 7%

isobutane. The Company rejected ethane from January through May and processed ethane in June through September. The Company has elected to reject ethane in October and November.

3Q 2019 4Q 2019 1Q 2020 2Q 2020 3Q 2020

Mont Belvieu Benchmark Price ($/Bbl) $18.89 $21.96 $17.02 $14.02 $19.13

SM NGL Realization ($/Bbl) $15.73 $17.84 $13.62 $10.43 $14.07

% Differential to Mont Belvieu 83% 81% 80% 74% 74%

Realizations by Quarter

Reflects Ethane Rejection(1)

23

Non-GAAP Definitions & Reconciliations

24

Adjusted EBITDAX: Adjusted EBITDAX is calculated as 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 the Company believes affect the comparability of operating results, including items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is also important as it is

considered among financial covenants under the Company’s Credit Agreement, a material source of liquidity for the Company. Please reference the Company’s 2019 Form 10-K and second quarter 2020 Form 10-Q for discussion of the Credit Agreement and

its covenants.

Adjusted net loss: Adjusted net loss excludes certain items that the Company believes affect the comparability of operating results, including items that are generally non-recurring in nature or 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, gains and losses on extinguishment of debt, and accruals for non-recurring matters.

Free cash flow: Free cash flow is calculated as net cash provided by operating activities before net change in working capital less capital expenditures before increase (decrease) in capital expenditure accruals and other.

Net debt: The total principal amount of outstanding senior secured and senior unsecured notes, senior convertible notes plus amounts drawn on the revolving credit facility (also referred to as total funded debt) less cash and cash equivalents.

Net debt-to-Adjusted EBITDAX: Net debt-to-Adjusted EBITDAX is calculated as Net Debt (defined above) divided by Adjusted EBITDAX (defined above). 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 2018.

NON-GAAP DEFINITIONS

Definitions of non-GAAP Measures as Calculated by the CompanyThe following non-GAAP measures are presented in addition to financial statements as the Company believes these metrics and performance measures are widely used by the investment community, including investors, research analysts and others, to

evaluate and compare investments among upstream oil and gas companies in making investment decisions or recommendations. These measures, as presented, may have differing calculations among companies and investment professionals and may not be

directly comparable to the same measures provided by others. A non-GAAP measure should not be considered in isolation or as a substitute for the related GAAP measure or any other measure of a company’s financial or operating performance presented in

accordance with GAAP. A reconciliation of each of these non-GAAP measures to the most directly comparable GAAP measure or measures is presented below. These measures may not be comparable to similarly titled measures of other companies.

Forward-Looking Non-GAAP MeasuresThe Company is unable to present a reconciliation of forward-looking net debt-to-Adjusted EBITDAX because components of the calculation (such as potential gains and losses related to derivatives, divestiture activity, or the extinguishment of debt) are

inherently unpredictable. Moreover, estimating the most directly comparable GAAP measures with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort.

Three Months Ended

September 30,

Nine Months Ended

September 30,

2020 2020

Net loss (GAAP) $ (98,292) $ (599,439)

Interest expense 41,519 123,385

Income tax benefit (22,969) (158,662)

Depletion, depreciation, amortization, and asset retirement obligation

liability accretion181,708 596,053

Exploration(2) 7,882 26,970

Impairment 8,750 1,007,263

Stock-based compensation expense 4,164 15,437

Net derivative (gain) loss 63,871 (314,269)

Derivative settlement gain 70,305 286,270

Net gain on divestiture activity - (91)

Gain on extinguishment of debt (25,070) (264,546)

Other, net 615 1,651

Adjusted EBITDAX (non-GAAP) $ 232,483 $ 720,022

Interest expense (41,519) (123,385)

Income tax benefit 22,969 158,662

Exploration(2) (7,882) (26,970)

Amortization of debt discount and deferred financing costs 4,506 13,084

Deferred income taxes (22,796) (159,064)

Other, net (2,991) (7,854)

Net change in working capital 16,843 (40,411)

Net cash provided by operating activities (GAAP) $ 201,613 $ 534,084

Three Months Ended

September 30,

Nine Months Ended

September 30,

2020 2020

Net loss (GAAP) $ (98,292) $ (599,439)

Net derivative (gain) loss 63,871 (314,269)

Derivative settlement gain 70,305 286,270

Net gain on divestiture activity - (91)

Impairment 8,750 1,007,263

Gain on extinguishment of debt (25,070) (264,546)

Other, net 615 1,767

Tax effect of adjustments(3) (25,708) (155,457)

Valuation allowance on deferred tax assets - 10,017

Adjusted net loss (non-GAAP) $ (5,529) $ (28,485)

Diluted net loss per common share (GAAP) $ (0.86) $ (5.28)

Net derivative gain (loss) 0.56 (2.77)

Derivative settlement gain 0.61 2.52

Net gain on divestiture activity - -

Impairment 0.08 8.88

Gain on extinguishment of debt (0.22) (2.33)

Other, net 0.01 0.02

Tax effect of adjustments(3) (0.23) (1.38)

Valuation allowance on deferred tax assets - 0.09

Adjusted net loss per diluted common share (non-GAAP) $ (0.05) $ (0.25)

Basic weighted-average common shares outstanding 114,371 113,462

Diluted weighted-average common shares outstanding 114,371 113,462

NON-GAAP RECONCILIATIONS

25

Adjusted EBITDAX(1) Adjusted Net Loss(1)

(1) See above “Definitions of non-GAAP measures as Calculated by the Company.”

(2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on

the consolidated statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(3) The tax effect of adjustments is calculated using a tax rate of 21.7% for the three and nine months ended September 30, 2020. This rate approximates the Company’s statutory tax rate adjusted for ordinary permanent differences.

(in thousands)(in thousands)

Three Months Ended

September 30,

Nine Months Ended

September 30,

2020 2020

Net cash provided by operating activities (GAAP) $ 201,613 $ 534,084

Net change in working capital 16,843 (40,411)

Cash Flow from Operations before net change in working capital 184,770 574,495

Exploration(3) 7,882 26,970

Discretionary cash flow $192,652 $ 601,465

Capital expenditures (GAAP) $ 109,568 $ 419,777

Increase (decrease) in capital expenditure accruals and other 11,491 (17,405)

Capital expenditures before increase (decrease) in capital expenditure

accruals and other121,059 402,372

Capitalized interest (4,841) (11,601)

Exploration(3) 7,882 26,970

Other (263) 260

Total capital spend $ 123,837 $ 418,001

Free cash flow (old method) $ 68,815 $ 183,464

Capitalized interest (4,841) (11,601)

Other (263) 260

Free cash flow (new method) $ 63,711 $ 172,123

As of

September 30,

2020

Senior Secured Notes(4) $ 512,160

Senior Unsecured Notes(4) 1,732,658

Revolving credit facility(4) 178,000

Total funded debt $ 2,422,818

Less: Cash and cash equivalents 10

Net debt $ 2,422,808

NON-GAAP RECONCILIATIONS

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(1) See above “Definitions of non-GAAP measures as Calculated by the Company.”

(2) In order to better align discussion of results with GAAP reporting, the Company will no longer use the non-GAAP measures discretionary cash flow and total capital spend. The Company has replaced these terms, respectively, with net cash provided by operating activities and capital

expenditures, both found in the GAAP Statement of Cash Flows, as adjusted for changes in net working capital accruals. These new terms will not be directly comparable to the prior non-GAAP definitions. The reconciliation above identifies the third quarter and year to date 2020

difference between the new free cash flow calculation method and the method used previously.

(3) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on

the consolidated statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(4) Amounts are from Note 5 – Long-term Debt in Part 1, Item 1 of the Company’s Form 10-Q for the quarter ended September 30, 2020.

RECONCILIATION OF PRIOR CALCULATION METHOD TO NEW METHOD

Free Cash Flow(1)(2)

Net Debt(1)

(in thousands)(in thousands)

27

Regional Maps

HOWARD COUNTY OPERATORS

28

SWEETIE PECK OPERATORS

29

SOUTH TEXAS OPERATORS

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Vice President - Investor Relations

303.864.2507

jsamuels@sm-energy.com

CONTACT INFORMATION

31

Jennifer Martin Samuels