2020 Earnings and 2021 Operating Plan

(1)

SM-ENERGY.COM

2020 Earnings and

2021 Operating Plan

FEBRUARY 17, 2021

(2)

2

DISCLAIMERS

Forward-looking statements

Non-GAAP financial measures

This 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 presentation include, among other things, capital expenditure guidance for 2021, guidance for the full year and first quarter 2021, estimated inventory life, possible inventory additions from contingent resources and prospective new intervals, inventory return estimates, targeted reinvestment rate, average lateral length of wells planned to be drilled in 2021, well costs per lateral foot, expected future condensate realizations and transportation costs, and the number of wells the Company plans to drill and complete in 2021; the Company’s 2021 goals, including: generating free cash flow, reducing leverage, increasing inventory and inventory value, meeting safety and emissions targets, and ESG performance. 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 (SEC), specifically the most recent 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 applicable securities laws.

Reserves Disclosure

The 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 natural gas liquids (NGLs), that, 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.

Proved reserves attributable to the Company as of December 31, 2020, are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $39.57 per Bbl of oil, $1.99 per MMBtu of natural gas, and $17.64 per Bbl of NGLs. At least 80% of the PV-10 of the Company’s estimate of its total proved reserves at December 31, 2020, was audited by Ryder Scott Company, L.P.

(3)

~$240

MM

3

PREMIER OPERATOR OF TOP-TIER ASSETS

2020 RESULTS EXCEEDED PLAN OBJECTIVES

Cash Flow Growth

2020 Plan Objectives:

Free Cash Flow Funded

Debt Reduction

2020 Results:

Free Cash Flow

(1)



~$500

MM

Principal Long-Term Debt Reduction

(2)

2



1

(4)

4

W E L L P E R F O R M A N C E

C A P I T A L E F F I C I E N C Y

PREMIER OPERATOR OF TOP-TIER ASSETS

▪ Strong well performance with Midland Basin and Austin Chalk

wells outperforming expectations

▪ Midland Basin well costs improved throughout the year,

averaging less than $500 per lateral foot in the fourth quarter

E M I S S I O N S R E D U C T I O N

S A F E T Y I S P R I O R I T Y # 1

1 ST

2020

Highlights and

Achievements

▪ Safety performance for 2020 was better than targeted and

place SM Energy in the top quartile among industry peers

based on available 2019 metrics

▪ Preliminary estimates of 2020 flaring were 0.8% of total

Company gas production, which reflects a more than 75%

reduction in flaring from Midland Basin production

I N V E N T O R Y A N D R E S E R V E S

▪ Year-end inventory and reserves reflect the exceptional

quality of our assets and success to date of our delineation

program in the Austin Chalk

(5)

2025

2024

1.500%

$65.5

PREMIER OPERATOR OF TOP-TIER ASSETS

$1,250

$1,000

$750

$500

$250

$0

2027

2026

2023

2022

2021

7/2021 11/2022 103.06% 11/2018 6.125% 5.000% 7/2018 102.50% 1/2024 10.000% 5.625% 6/2020 102.81% 1/2025 6/2025 6.750% 9/2021 103.38% 9/2026 6.625% 1/2022 104.97% 1/2027

$419

$417

$93

_$277

$212

$349

$447

Second Lien Secured

$500

(1) As of December 31, 2020.

(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) Borrowing base and Commitments are subject to certain covenants if second lien debt capacity is used to redeem unsecured debt.

$1.1B

(3)

Borrowing Base

& Commitments

Coupon

Initial Call Date

Initial Call Price

Maturity Date

Net debt-to-Adjusted EBITDAX

(2)

2.3 times

(1)

Debt Maturities

( 1 )

in millions

YTD Principal Debt Reduction

~$500 million

(1)

YTD Maturities through 2022 reduced by

~$370 million

(1)

Liquidity

~$965 million

(1)

FOCUSED ON IMPROVING BALANCE SHEET STRENGTH

6/2022

(6)

6

Plan Overview &

Guidance

(7)

7

PREMIER OPERATOR OF TOP-TIER ASSETS

LONG-TERM STRATEGIC DIRECTION: FIVE-YEAR PLAN

Strategic

Objectives:

Free cash flow

(1)

_generation

• Maximize cash flow over five years

• Sustain <75% reinvestment rate

(1)

_{beginning in 2022 and}

beyond

(2)

OPTIMIZE ACTIVITY LEVEL FOR

SUSTAINABLE FREE CASH FLOW

(1)

Establish an optimal activity level to maximize free cash

flow and reduce leverage

DEMONSTRATE MEASURABLE,

TOP-TIER ESG STEWARDSHIP

Short-term annual cash bonus and long-term incentive

compensation plan targets include key environmental and

safety metrics

Key Priorities:

Improve balance sheet strength

• FCF generation through 2024 expected to enable

retirement of all debt due through 2024

(2)

• Target less than 2x net debt-to-Adjusted EBITDAX

(1)

by year-end 2022

(2)

Maintain top-tier inventory

• Low breakeven prices demonstrate high-quality asset

base that is resilient to downside and offers substantial

upside

Differential ESG

• We listened to our investors and have changed our

long-term incentive program to measure performance against

targets for free cash flow, leverage, GHG emissions,

safety and spills; short-term incentive program now

includes a free cash flow component

(8)

8

PREMIER OPERATOR OF TOP-TIER ASSETS

LONG-TERM OUTLOOK

2.3

YE20 YE21e YE22e YE23e YE24e YE25e

Less than 2x

Free cash flow

(1)(2)

Reinvestment rate

(1)(2)

2020 2021e 2022e 2023e 2024e 2025e

69%

Ta r g e t l e s s t h a n 2 x b y Y E 2 2

M a x i m i z e o v e r 5 - y e a r p e r i o d

S u s t a i n < 7 5 % r a t e 2 0 2 2 & b e y o n d

~$240MM

(1) Free cash flow, Net debt-to-Adjusted EBITDAX, and reinvestment rate are non-GAAP financial measures. See “Definitions of non-GAAP measures as Calculated by the Company” and related reconciliations in the Appendix. (2) Based on strip pricing as of January 28, 2021 and current costs.

(9)

Guidance

FY 2021

Capital Expenditures

(3)

_($MM)

$650 - $675

Total Production

(MMBoe)

47 - 50

Total Production

(MBoe/d)

129 - 137

Oil percentage

~52-53%

LOE

(per Boe)

$4.50 - $5.00

Transportation

(per Boe)

$2.80 - $3.00

Production & Ad Valorem taxes

(4)

_{(per Boe)}

~$2.15

G&A

(5)

_($MM)

~$100

Exploration Expense

($MM)

_~$50

DD&A

(per Boe)

$16 - $18

2021 GOALS AND PLAN GUIDANCE

(1)

Organically grow inventory and

inventory value

Key Metrics

RIGHT-SIZING ACTIVITY LEVELS TO ACHIEVE SUSTAINABLE REINVESTMENT RATE

(2)

(1) As of February 17, 2021.

(2) Free cash flow and 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.

(3) Capital expenditures before changes in capital expenditure accruals and other.

(4) Production & Ad Valorem taxes estimated at ~4.5% of pre-hedge revenue + ~$0.50, respectively. (5) Includes ~$12 million non-cash compensation.

Q 1 2 0 2 1 G U I D A N C E

▪ Capital expenditures

(3)

: ~$180million

Reduce leverage

Generate positive free cash flow

(2)

2021 Goals

Meet AXPC top-quartile rank for safety

and emissions metrics

(10)

10

CAPITAL PROGRAM

(1)

CAPITAL PROGRAM IN 2021 SETS PACE TO MEET LONG-TERM OBJECTIVES

Right-sizing capital expenditures

(2)

_for

long-term sustainability

Drilling and

Completion

~90%

Capital Expenditures

(2)

$650-$675MM

~6%

~4%

(1) Capital expenditures before changes in capital expenditure accruals and other. (2) Based on strip pricing as of January 28, 2021 and current costs.

Capital Expenditures

(2)

2021

2019 2020 2021e 2022e 2023e 2024e 2025e

~$540MM

$650-$675MM

~70%

Midland Basin

~30%

South Texas

~$1 Billion

Budget

(11)

2021 Oil Volumes Hedged

(1)

SM Energy Hedge Program

▪ ~19,890 MBbls

(1)

_{, or approximately 75-80%}

(1)

_{of expected 2021}

oil production, hedged to WTI at an average price $41.37

(weighted average of collar floors and swaps)

▪ ~15,100 MBbls, or approximately 60-65% of expected 2021

Midland Basin oil production is hedged to the local price point at

a positive $0.77/Bbl basis

▪ ~79,740 BBtu

(2)

_{, or approximately 85% of expected natural gas}

production hedged in 2021

▪ ~50,250 BBtu hedged to HSC at an average weighted price of

$2.44/MMBtu and ~29,490 BBtu hedged to WAHA at an average

weighted price of $1.81/MMBtu

RISK MANAGEMENT

HEDGING SUMMARY

(1) Hedges include oil swaps and collars to WTI only; excludes basis swaps and roll differential hedges. (2) Hedges include natural gas swaps to HSC and WAHA.

~75-80%

Oil

Natural gas

2021 Natural Gas Volumes Hedged

(2)

~85%

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12

2020 Regional Results and

2021 Operations Plan

(13)

TOP-TIER EXECUTION, WELL PERFORMANCE AND CAPITAL EFFICIENCY

MIDLAND BASIN

MARTIN

RockStar

HOWARD UPTON

Sweetie Peck

MIDLAND

2 0 2 1 O P E R A T I N G P L A N

O P E R A T I N G D E T A I L S

(2)

~

82,000

Rigs

Running:

Completion

Crews:

N E T A C R E S

(1) Breakeven 10% IRR assumes natural gas at $2.50/Mcf and 43% NGL to WTI pricing. (2) As of February 17, 2021. ECTOR GLASSCOCK REAGAN ANDREWS

2 0 2 1 P L A N D E T A I L S

▪ ~72 net completions and ~55 net drilled wells planned

▪ ~11,300’ expected average lateral feet per well

▪ ~45% Boe PDP decline expected (YE20 - YE21)

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

▪ 2021-2022 drilling program expected breakeven flat pricing of

$16 - $31/Bbl NYMEX

(1)

L E A D I N G E D G E C A P I T A L C O S T S

(14)

765 1,025 1,503 2,019 2017 2018 2019 2020 1.0 0.5

Jan. '19 June '19 Dec. '19 June '20 Dec. '20

14

LEADING DC&E COSTS; 2021 PLAN BASED ON ~$520 PER LATERAL FOOT

MIDLAND BASIN: TOP-TIER CAPITAL EFFICIENCY

Drilling and Completion

Efficiency Gains

Drilled and completed feet per day

(1)

54%

DRILLING IMPROVEMENT

164%

COMPLETION IMPROVEMENT

Longer Laterals

Average Lateral Length Completed

Lower Sand Costs

Indexed to January 2019

(2) 9,300

11,420

2017 2018 2019 2020

23%

INCREASE IN LATERAL LENGTH

49%

LOWER SAND COSTS

(1) Drilling: total lateral feet delivered per rig per day, spud to rig release. Completion: lateral feet completed per fleet per day. (2) Sand costs exclude last mile logistics as there is variability in these charges.

510

562

645

783

(15)

15

FOCUSED ON EXECUTION AND RETURNS ENHANCEMENT

SOUTH TEXAS

DIMMIT COUNTY WEBB COUNTY North Area South Area East Area

2 0 2 1 O P E R A T I N G P L A N

O P E R A T I N G D E T A I L S

(2)

~158,000

N E T A C R E S

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

Rigs

Running:

(1) Breakeven 10% IRR assumes natural gas at $2.50/Mcf and 43% NGL to WTI pricing.

Completion

Crews:

2 0 2 1 P L A N D E T A I L S

▪ ~21 net completions and ~39 net drilled wells planned

▪ ~12,000’ expected average lateral feet per well

▪ ~$520/lateral foot expected DC&E costs

▪ ~20% Boe PDP decline expected (YE20 - YE21)

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 mid 2023

▪ Condensate prices improved by $9-$10 per Bbl relative to prior contract terms in 4Q20

A U S T I N C H A L K S U C C E S S

▪ 2020 Austin Chalk wells have an expected breakeven flat oil price range of $13

-$28/Bbl NYMEX

(1)

_{at go forward development capital}

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16

OUTSTANDING PERFORMANCE FROM RECENT AUSTIN CHALK DELINEATION WELLS

SOUTH TEXAS: AUSTIN CHALK SUCCESS CONTINUES

▪ 2020 Austin Chalk completions have an expected

breakeven flat oil price range of $13 - $28/Bbl

NYMEX

(1)

_{at go forward development capital}

▪ Austin Chalk operating costs per Boe are ~35-40%

lower than existing average SM Energy South Texas

costs

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

(2)

(1) Breakeven 10% IRR assumes natural gas at $2.50/Mcf and 43% NGL to WTI pricing. (2) Includes oil and NGLs based on IP30.

Austin Chalk Wells Currently Producing

Austin Chalk Wells

200 400 600 800 1,000 0 60 120 180 240 300 360 420 480 540 600 660 720 780 840 900

Cu

mula

tiv

e

P

roduction

Days on Production

2020 Average

MBoe, 3-stream

New wells producing

61-81%

liquids

(2)

Completed through 2020

2021 planned completions

of delineation and

(17)

0 100,000 200,000 300,000 400,000 500,000 0 10 20 30 40 50 60 70 80 90 100 110

Cu

mul

a

tiv

e

P

roduction

(2) (2 -s tr ea m B oe pe r W el l)

Months on Production

0 100,000 200,000 300,000 400,000 500,000 0 10 20 30 17

NOT THE OLD EAST TEXAS AUSTIN CHALK

SOUTH TEXAS: AUSTIN CHALK HISTORICAL COMPARISON

(1)

Horizontal Modern Frac

Modern Eagle Ford Oily

Horizontal Traditional Frac Initial Horizontal Initial Vertical Delaware Basin(3)

Improved landing zones and continuous

optimization of completion design

Superior liquids content and returns

compared to average Delaware Basin well

(1) Source: IHS public data.

Briscoe G 109H achieved payout within

first 9 months

Austin Chalk Austin Chalk

Transformed from a historical natural

fracture play to a repeatable horizontal

unconventional play

(3) Source: IHS public data, average of modern frac’d, horizontal wells since 2015.

Months on Production

Cu

mula

tiv

e

P

roduction

(2 -s tr ea m B oe pe r W el l)

(18)

18

(19)

Price revision primarily relates to Eagle

Ford natural gas wells

YEAR-END 2020 PROVED RESERVES

Note: Calculated in accordance with SEC Pricing at $39.57 per barrel of oil NYMEX, $1.99 per MMBtu of natural gas at Henry Hub and $17.64 per barrel of natural gas liquids (“NGLs”) at Mt. Belvieu.

57%

Proved Developed

43%

oil

43%

natural gas

14%

NGLs

Per the SEC 5-Year Rule, reduced

reinvestment rate 2021-2025 deferred

economic wells beyond PUD time period

Reserve adds

(including performance revisions)

89 MMBoe

46

3

89

65

33

462

33

405

0 100 200 300 400 500 600 YE19 Proved Reserves

Production Net Divestitures Reserve Additions and Performance Revisions Revisions - SEC 5-Year Rule Revisions -Price YE20 Proved Reserves

P

rov

e

d

Res

e

rv

e

s

(

M

Bo

e

)

(20)

20

Midland Basin

expected inventory

(1)

_:

Exceptional quality inventory

>50%

average return

(1)

Total Company

expected inventory

(1)

_:

Inventory upside from contingent resources

and prospective new intervals could add

another 5+ years in the Midland Basin

Enverus Research

(2)

Years of Sub $40 WTI and

$2.25 HH Inventory

8

(1) Based on $50/Bbl oil, $2.50/MMBtu gas, and $21/BblNGL’s. (2) Enverus Research, February 10, 2021.

HIGH QUALITY MULTI-FORMATION INVENTORY

COMPELLING ECONOMICS AT LOW COMMODITY PRICES

years

=

SM Energy inventory resilient

at low commodity prices

(21)

21

PREMIER OPERATOR OF TOP-TIER ASSETS

J.P. Morgan Research

(6)

_:

_{These (Austin Chalk)}

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.

RSEG/Enverus Research

(7)

_:

_{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%.

RSEG/Enverus Research

(5)

_:

_{SM only needs to reinvest}

87% of cash flow to hold oil production flat at 4Q20 levels from

2021-2024 at strip then flat $45 WTI and $2.75HH; We view

XEC and SM as the most attractive SMID oil equities due to a

combination of NAV upside at $50 WTI and $2.75HH, low-cost

inventory, sustainable cash flow, and production profiles at

strip prices.

RBC Equity Research

(4)

_:

_{We upgrade SM to Outperform}

due to (1) rapid pace of de-leverage, (2) top-tier Permian

economics, and (3) upside in the Austin Chalk. We believe SM

shares provide investors beta to higher oil prices that are

supported by solid fundamentals and an improving financial

position. Over the last couple of years, we think the market

was positively surprised with performance at RockStar

(Permian) but we see the asset still undervalued and the

Austin Chalk as a new value catalyst in 2021.

J.P. Morgan Research

Jayaram Award

Midland Basin Performance, December 2020

Stifel Research

(3)

_:

_{Raising our target price based on}

a stronger Austin Chalk type curve. We anticipate new

wells will be comparable to three 2020 Austin Chalk

wells that appear to generate competitive returns with

the Company’s Permian Basin assets. SM wells in the

Midland Basin have outperformed most competitors

despite tighter than average well spacing.

RBC Equity Research

(2)

_:

_{SM added to Global}

Energy Best Ideas list as a top global name based on

top-tier returns in the core Permian development,

visibility towards improving balance sheet, and the

South Texas Austin Chalk catalyst.

J.P. Morgan Research

(1)

_:

_{We are upgrading SM}

given a better FCF at higher oil prices, as well as giving

more credit to the emerging South Texas Austin Chalk

play in our NAV.

(1) J.P. Morgan Research, Arun Jayaram, February 3, 2021. (7) RSEG / Enverus research, October 18, 2020.

THE EXPERTS AGREE…

(5) RBC Equity Research, Scott Hanold, January 10, 2021. (3) Stifel Research, Michael Scialla, January 12, 2021.

(22)

22

(23)

Performance

(24)

2020 PERFORMANCE

24

Adjusted EBITDAX

(1)

$975

Production

126.9 Free cash flow

(1)

$240

MBoe/d

million

Key Metrics

(1) Adjusted net income (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.

4Q20

2020

Production and Pricing

Total Production (MMBoe) 11.3 46.4 Total Production (MBoe/d) 122.4 126.9

Oil percentage 51% 50%

Pre-Hedge Realized Price ($/Boe) $28.42 $24.26 Post-Hedge Realized Price ($/Boe) $34.19 $31.82

Costs (per Boe)

LOE $4.10 $3.97

Transportation $2.89 $3.06 Production & Ad Valorem taxes $1.53 $1.40 Total Production Expenses $8.52 $8.43

Cash Production Margin (pre-hedge) $19.90 $15.83

G&A (Cash) $1.88 $1.89 G&A (Non-Cash) ($0.10) $0.25

Operating Margin (pre-hedge) $18.12 $13.69

DD&A $16.77 $16.91

Earnings

GAAP Earnings (per share) $(1.44) $(6.72) Adjusted net income (loss)(1)_{(per share)} _$0.02 _$(0.23)

Adjusted EBITDAX(1)_($MM) _$255.4 _$975.4

Free cash flow ($MM)

Net cash provided by operating activities (GAAP) $256.9 $790.9 Net change in working capital $(52.0) $(11.6) Net cash provided by operating activities before net change in working capital $204.9 $779.4 Capital Expenditures (GAAP) $128.0 $547.8 Increase (decrease) in capital expenditure accruals and other $9.4 $(8.0) Capital expenditures before increase in capital expenditure accruals and other $137.4 $539.8

(25)

TWO TOP-TIER AREAS OF OPERATION

4Q 2020 REALIZATIONS BY REGION

Midland

Basin

Texas

South

Total

Production Volumes

Oil (MBbls) 5,348 441 5,790

Gas (MMcf) 12,601 12,724 25,325

NGL (MBbls) 5 1,249 1,254

Total (Mboe) 7,454 3,811 11,264

Revenue (in thousands)

Oil $217,453 $17,259 $234,712

Gas $30,200 $32,131 $62,331

NGL $106 $23,005 $23,110

Total $247,758 $72,395 $320,153

Expenses (in thousands)

LOE $37,584 $8,587 $46,171

Ad Valorem $2,774 $1,517 $4,292

Transportation $81 $32,503 $32,584

Production Taxes $11,830 $1,087 $12,917

Per Unit Metrics

Realized Oil Per Bbl $40.66 $39.11 $40.54

% of Benchmark - WTI 95% 92% 95%

Realized Gas per Mcf $2.40 $2.53 $2.46

0 % of Benchmark - NYMEX Henry Hub 90% 95% 92% Realized NGL per Bbl $20.20 $18.42 $18.43

% of Benchmark - HART 93% 85% 85%

Realized Price per Boe $33.24 $19.00 $28.42

LOE per Boe $5.04 $2.25 $4.10

Ad Valorem per Boe $0.37 $0.40 $0.38

Transportation per Boe $0.01 $8.53 $2.89 Production Tax per Boe $1.59 $0.29 $1.15 Production Tax as % of Pre-hedge Revenue 4.8% 1.5% 4.0% Production Margin per Boe $26.23 $7.53 $19.90

Benchmark Pricing

NYMEX WTI Oil ($/Bbl) $ 42.66 NYMEX LLS Oil ($/Bbl) $ 44.02 NYMEX Henry Hub Gas ($/MMBtu) $ 2.66 Hart Composite NGL ($/Bbl) $ 21.68

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26

WELLS DRILLED, FLOWING COMPLETIONS AND DUC COUNT

ACTIVITY BY REGION

(1) South Texas DUC Count reduced by 3 net wells from December 31, 2019 as a result of the previously announced agreement with a third party to fund the majority of completion costs for 6 gross wells. (2) South Texas DUC Count includes 13 gross / 13 net wells that are not included in our five-year development plan.

Wells Drilled

Flowing Completions

DUC Count

(1)(2)

4Q20 2020 YTD 4Q20 2020 YTD As of December 31, 2020 Gross Net Gross Net Gross Net Gross Net Gross Net

Midland Basin

Sweetie Peck

6

5

25

21

7

5

15

12

16

14 RockStar

16

14

70

63

19

18

65

61

50

44 Midland Basin total

22

19

95

84

26

23

80

73

66

58 South Texas

(1)(2)

Eagle Ford

-

17

15 Austin Chalk

7

14

14 -

-

4

14

13 South Texas total

7

14

14 -

-

4

31

28 Total

29

26

109

98

26

23

84

77

97

86

(27)

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

LEASEHOLD SUMMARY

MIDLAND BASIN

NET ACRES

~82,000

Midland Basin

Sweetie Peck

(2)

18,000

RockStar

64,300

Midland Basin total

82,300

South Texas

158,000

Rocky Mountain Other

10,300

Other Areas / Exploration

26,400

Total

277,000

SOUTH TEXAS

NET ACRES

~158,000

As of December 31, 2020

Net Acres

(1)

(1) Includes developed and undeveloped oil and natural gas leasehold, fee properties, and mineral servitudes held as of December 31, 2020. (2) Sweetie Peck acreage includes ~1,700 net drill-to-earn acreage.

(28)

Differential reflects NGL composite

barrel product mix as well as

transportation and fractionation fees

NGL REALIZATIONS

28

NGL price realizations tied to

Mont Belvieu, fee-based contracts

SM NGL Composition

32%

16%

9%

11%

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 52% ethane, 22% propane, 11% natural gasoline, 8% normal butane, and 7% isobutane. The Company has elected to reject ethane for January and February 2021.

4Q 2019

1Q 2020

2Q 2020

3Q 2020

4Q 2020

Mont Belvieu Benchmark Price

($/Bbl)

$21.96

$17.02

$14.02

$19.13

$21.68

SM NGL Realization

($/Bbl)

$17.84

$13.62

$10.43

$14.07

$18.43

% Differential to Mont Belvieu

81%

80%

74%

85%

Realizations by

Quarter

(29)

$0.00 $3.00 $6.00 $9.00 $12.00 $15.00 2020Q1 2020Q2 2020Q3 2020Q4 $0.00 $1.00 $2.00 $3.00 2020Q1 2020Q2 2020Q3 2020Q4 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 2020Q1 2020Q2 2020Q3 2020Q4

SM ENERGY AUSTIN CHALK: TOP-TIER ECONOMICS

Austin Chalk operating

costs per Boe are 35-40%

lower than current blended

South Texas operating costs

Transportation

per Boe

NGL benchmark pricing based on industry

standard composite barrel comprised of: Ethane

36.5%, Propane 31.8%, Normal Butane 11.2%,

Isobutane 6.2%, Pentane+ 14.3%

AC only

Total South Texas

LOE

per Boe

Total South Texas

AC only

Production Expenses

(1)

_{per Boe}

AC only

Total South Texas

(30)

2020 PROVED RESERVES BY REGION

30

Note: Calculated in accordance with SEC Pricing at $39.57 per barrel of oil NYMEX, $1.99 per MMBtu of natural gas at Henry Hub and $17.64 per barrel of natural gas liquids (“NGLs”) at Mt. Belvieu.

SEC Pricing

YE 2020

Midland

Basin

South

Texas

Total

Oil (MMBbl)

150.9

21.8

172.7 Gas (Bcf)

425.3

626.8 1,052.0

NGL (MMBbl)

0.2

56.4

56.6 Total (MMBoe)

222.0

182.6

404.6 % Proved Developed

58%

55%

57%

2020

2019

% change

Oil ($/Bbl)

$39.57

$55.69

(29)%

Gas ($/MMBtu)

$1.99

$2.58

(23)%

NGLs ($/Bbl)

$17.64

$22.68

(22)%

(31)

(32)

Oil Swaps

Oil Collars

Midland - Cushing

Oil Basis Swaps

NYMEX WTI - ICE Brent

Oil Basis Swaps

NYMEX WTI Roll Basis

Swaps

Period Volume (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) Q1 2021 3,724 $43.20 551 $51.96 $48.97 3,349 $0.79 900 ($7.86) 3,736 ($0.24) Q2 2021 5,508 $40.88 - - - 4,172 $0.81 910 ($7.86) 4,743 ($0.16) Q3 2021 5,363 $41.16 - - - 3,756 $0.75 920 ($7.86) 4,326 ($0.18) Q4 2021 4,744 $39.85 - - - 3,824 $0.71 920 ($7.86) 3,831 ($0.16) Q1 2022 2,010 $44.81 270 $55.84 $50.00 2,222 $1.15 900 ($7.78) 2,907 $0.11 Q2 2022 1,953 $44.75 273 $53.88 $50.00 2,374 $1.15 910 ($7.78) 2,841 $0.10 Q3 2022 1,938 $44.63 276 $52.47 $50.00 2,442 $1.15 920 ($7.78) 2,782 $0.11 Q4 2022 1,923 $44.58 276 $51.27 $50.00 2,462 $1.15 920 ($7.78) 2,748 $0.10 Q1 2023 294 $45.20 - - - -Q2 2023 333 $45.18 - - - -Q3 2023 304 $45.20 - - - -Q4 2023 259 $45.23 - - -

-IF HSC Gas Swaps

WAHA Gas Swaps

Period Volume (BBtu) $/MMBtu (2) Volume (BBtu) $/MMBtu (2) Q1 2021 11,592 $2.48 6,544 $1.76 Q2 2021 13,672 $2.45 7,230 $1.76 Q3 2021 12,575 $2.40 8,086 $1.88 Q4 2021 12,412 $2.41 7,627 $1.82 Q1 2022 8,208 $2.85 4,485 $2.58 Q2 2022 6,808 $2.34 3,079 $2.09 Q3 2022 6,934 $2.37 3,085 $2.19 Q4 2022 6,982 $2.47 3,067 $2.22

Propane Swaps

Propane Collars

Normal Butane

Swaps

Period Volume (MBbls) $/Bbl (2) Volume (MBbls) Ceiling $/Bbl(2) Floor $/Bbl(2) Volume (MBbls) $/Bbl (2) Q1 2021 714 $22.44 - - - 33 $30.87 Q2 2021 818 $22.14 - - - 37 $30.87 Q3 2021 854 $22.16 - - - 37 $30.87 Q4 2021 824 $22.15 - - - 36 $30.87 Q1 2022 231 $22.99 58 $27.30 $22.05 - -Q2 2022 - - 59 $27.30 $22.05 - -Q3 2022 - - 58 $27.30 $22.05 - -Q4 2022 - - 60 $27.30 $22.05 - -32

BY QUARTER

OIL, GAS, AND NGL DERIVATIVE POSITIONS

(1)

Oil

Gas

NGLs

(1) Includes derivative contracts for settlement at any time during the first quarter of 2021 and later periods, entered into as of 2/17/2021. (2) Weighted-average contract price.

(33)

Fourth Quarter & Full Year 2020

(34)

34

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 2020 Form 10-K for discussion of the Credit Agreement and its covenants.

Adjusted net income (loss): Adjusted net income (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 Company

The 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 Measures

Discussion in this presentation of the 2021 operating plan and guidance include forward-looking net debt-to-Adjusted EBITDAX, free cash flow, capital expenditures, and reinvestment rate, which are non-GAAP measures. The Company is unable to provide reconciliations of these forward-looking non-GAAP measures because components of the calculations are inherently unpredictable, such as changes to current assets and liabilities, the timing of changes in capital accruals, unknown future events, and estimating future certain GAAP measures. The inability to project certain components of the calculation would significantly affect the accuracy of a reconciliation.

(35)

Three Months Ended December 31,

Twelve Months Ended December 31,

2020 2020

Net loss (GAAP) $ (165,175) $ (764,614)

Interest expense 40,507 163,892 Income tax benefit (33,429) (192,091) Depletion, depreciation, amortization, and asset retirement obligation

liability accretion 188,934 784,987 Exploration(2) _10,571 _37,541

Impairment 8,750 1,016,013 Stock-based compensation expense (438) 14,999 Net derivative (gain) loss 152,693 (161,576) Derivative settlement gain 64,991 351,261 Net gain on divestiture activity - (91) Gain on extinguishment of debt (15,535) (280,081) Other, net 3,514 5,165

Adjusted EBITDAX (non-GAAP) $ 255,383 $ 975,405

Interest expense (40,507) (163,892) Income tax benefit 33,429 192,091 Exploration(2) _(10,571) _(37,541)

Amortization of debt discount and deferred financing costs 4,620 17,704 Deferred income taxes (33,476) (192,540) Other, net (4,020) (11,874) Net change in working capital 52,002 11,591

Net cash provided by operating activities (GAAP) $ 256,860 $ 790,944

2020 2020

Net loss (GAAP) $ (165,175) $ (764,614)

Net derivative (gain) loss 152,693 (161,576) Derivative settlement gain 64,991 351,261 Net gain on divestiture activity - (91) Impairment 8,750 1,016,013 Gain on extinguishment of debt (15,535) (280,081) Other, net 3,554 5,321 Tax effect of adjustments(3) _(46,536) _(201,994)

Valuation allowance on deferred tax assets - 10,017

Adjusted net income (loss) (non-GAAP) $ 2,742 $ (25,744)

Diluted net loss per common share (GAAP) $ (1.44) $ (6.72)

Net derivative gain (loss) 1.33 (1.42) Derivative settlement gain 0.57 3.09 Net gain on divestiture activity - -Impairment 0.08 8.93 Gain on extinguishment of debt (0.14) (2.46) Other, net 0.03 0.05 Tax effect of adjustments(3) _(0.41) _(1.79)

Valuation allowance on deferred tax assets - 0.09

Adjusted net income (loss) per diluted common share (non-GAAP) $ 0.02 $ (0.23)

Basic weighted-average common shares outstanding 114,528 113,730 Diluted weighted-average common shares outstanding 114,528 113,730

NON-GAAP RECONCILIATIONS

Adjusted EBITDAX

(1)

Adjusted net income (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 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 twelve months ended December 31, 2020. This rate approximates the Company’s statutory tax rate adjusted for ordinary permanent differences.

(in thousands) (in thousands)

(36)

2020

Capital expenditures before decrease in capital expenditure accruals and other $ 539,820

Divided by:

Cash flow from operations before net change in working capital 779,353

Reinvestment rate 69%

2020 2020

Net cash provided by operating activities (GAAP) $ 256,860 $ 790,944

Net change in working capital (52,002) (11,591)

Cash flow from operations before net change in working capital 204,858 779,353

Exploration(3) _10,571 _37,541

Discretionary cash flow $ 215,429 $ 816,894

Capital expenditures (GAAP) $ 128,008 $ 547,785

Increase (decrease) in capital expenditure accruals and other 9,440 (7,965)

Capital expenditures before increase (decrease) in capital expenditure

accruals and other 137,448 539,820

Capitalized interest (4,206) (15,807) Exploration(3) _10,571 _37,541

Other 4,368 4,628

Total capital spend $ 148,181 $ 566,182

Free cash flow (old method) $ 67,248 $ 250,712

Capitalized interest (4,206) (15,807)

Other 4,368 4,628

Free cash flow (new method) $ 67,410 $ 239,533

As of December 31,

2020

Senior Secured Notes(4) _{$ 512,160}

Senior Unsecured Notes(4) _1,674,581

Revolving credit facility(4) _93,000

Total funded debt $ 2,279,741 Less: Cash and cash equivalents 10

Net debt $ 2,279,731

NON-GAAP RECONCILIATIONS

36

(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 fourth quarter and full year 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 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 2, Item 8 of the Company’s Form 10-K for the year ended December 31, 2020.

RECONCILIATION OF PRIOR CALCULATION METHOD TO NEW METHOD

Free Cash Flow

(1)(2)

Net Debt

(1)

(in thousands) (in thousands)

Reinvestment Rate

(1)

(37)