1Q 2020 Financial & Operating Results

APRIL 29, 2020

SM-ENERGY.COM

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 and reconciliations to the directly 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,"

"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 production, 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.

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~$81MMFREE 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

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

C A P I T A 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

~$91MMDEBT REDUCTION

STRONG FIRST QUARTER AND SCALED-BACK 2020 CAPITAL

PREMIER OPERATOR OF TOP-TIER ASSETS

▪ Generated $81MM of free cash flow(1)

▪ Production of 12.4 MMBoe (135.9 MBoe/d) and 51%

oil at high-end of guidance

▪ $41MM market purchases of 2022 bonds for $28.3MM

▪ $50MM reduction in credit facility balance

▪ Net Debt-to-Adjusted EBITDAX at 2.45x(1)

(1) 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. Net debt-to-Adjusted EBITDAX as of March 31, 2020..

▪ Capital expenditures reduced ~20%

▪ Borrowing Base redetermined at $1.1B with

Commitments of $1.1B

FIRST QUARTER 2020 PERFORMANCE

4

Adjusted EBITDAX(1)

$286

Production

135.9

Free Cash Flow(1)

$81

Q1 2020Production and Pricing

Total Production (MMBoe) 12.4

Total Production (MBoe/d) 135.9

Oil percentage 51%

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

Total Production Expenses $9.67

Cash Production Margin (pre-hedge) $18.97

G&A (Cash) $1.85

G&A (Non-Cash) $0.37

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 ($MM)

Net cash provided by operating activities (GAAP) $218.1

Net change in working capital (GAAP) $18.5

Net cash provided by operating activities before net change in working capital $236.6

Less:

Capital Expenditures (GAAP) $139.9

Increase in capital expenditure accruals and other (GAAP) $16.8

Free Cash Flow(1) $80.5

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.

Net debt-to-Adjusted EBITDAX(3)

Initial Call Date

20252024

Coupon 1.500%

D e b t Matur i t i e s ( 1 )

$172.5

BALANCE SHEET FOCUSLEVERAGE METRICS IMPROVED

5

$1,250

$1,000

$750

$500

$250

$0

202720262023202220212020

Initial Call Price

Maturity Date 7/2021 11/2022

103.06%

11/2018

6.125% 5.000%

7/2018

102.50%

01/2024

5.625%

6/2020

102.81%

06/2025

6.750%

9/2021

103.38%

09/2026

6.625%

1/2022

104.97%

01/2027

$436.0$500 $500 $500 $500

$1.1BCommitments &

Borrowing Base

Liquidity of $1B(2)

Borrowing base re-determined in April 2020

in millions

$72

(1) As of March 31, 2020; Commitments and Borrowing Base as of April 29, 2020.

(2) Pro-forma for the Company’s senior secured revolving credit facility borrowing base redetermination which was completed on April 29, 2020.

(3) Net debt-to-Adjusted EBITDAX is a non-GAAP measure. See the “Non-GAAP Definitions and Reconciliations” section in the Appendix.

2.45x

2Q – 4Q 2020 Oil Volumes Hedged(1)

At prices > $55/Bbl

2020 Hedge Program▪ ~14,340 MBbls(1) of 2Q – 4Q oil production hedged to WTI;

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

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STRONG HEDGE PROTECTION AT CURRENT OIL PRICES

HEDGING SUMMARY

(1) 2Q – 4Q 2020 oil hedges include oil swaps and collars to WTI only; excludes basis swaps.

(2) 2Q – 4Q 2020 natural gas hedges include IF HSC and WAHA gas swaps.

~14,340 MBbls

TOP-TIER EXECUTION, WELL PERFORMANCE AND CAPITAL EFFICIENCY

MIDLAND BASIN

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MARTIN

RockStar

HOWARD

UPTON

Sweetie PeckMIDLAND

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

▪ ~$6.8MM expected average well cost

▪ ~48% Boe PDP decline (YE19 - YE20)

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

O P E R AT I N G D E TA I L S(3)

~82,000Rigs

Running:

Completion

Crews:N E T A C R E S

(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.

765

1,025

1,503

1,740

2017 2018 2019 Q1'20

1.0

0.6

Jan.'19

Apr.'19

July'19

Oct.'19

Jan.'20

Mar.'20

8

LEADING DC&E COSTS REDUCED TO ~$600 PER LATERAL FOOT

MIDLAND BASIN: TOP-TIER CAPITAL EFFICIENCY

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

53%DRILLING IMPROVEMENT

127%COMPLETION IMPROVEMENT

Longer LateralsAverage Lateral Length Completed(2)

Lower Sand CostsIndexed to January 2019(3)

9,300

11,300

2017 2018 2019 2020REVISED PLAN

22%INCREASE IN LATERAL LENGTH

43%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

778

2017 2018 2019 Q1'20

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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)

Rigs Running: ~159,000N E T A C R E S

(1) As of April 30, 2020.

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

~$620/lateral foot

▪ ~27% Boe PDP decline (YE19 - YE20)

A U S T I N C H A L K S U C C E S S▪ Briscoe G 109H, completed in the fourth quarter of 2020, continues to

outperform expectations

0

50

100

150

200

250

300

0 20 40 60 80 100 120 140

Cu

mu

lati

ve

Pro

du

cti

on

Days on Production

10

HIGHER OIL CONTENT = HIGHER RETURNS

SOUTH TEXAS: AUSTIN CHALK SUCCESS CONTINUES

Briscoe G 109H

Continued outperformance v. expectations

Total Production (MBoe; 3-stream)

Oil Production (MBo)

Demonstrating Geographic Expanse

Note: Boe rates provided are 3-stream.

Briscoe C (SA1) State 108H

IP30: 1,693 Boe/d

IP30 oil: 779 Bbl/d

Lateral Length: 11,269’

% liquids: 73%

API Gravity: 50.0

Watson (SA2) State 167H

IP30: 3,096 Boe/d

IP30 oil: 651 Bbl/d

Lateral Length: 12,875’

% liquids: 56%

API Gravity: 56.7

Briscoe G 109H

IP30: 2,634 Boe/d

IP30 oil: 1,581 Bbl/d

Lateral Length: 6,502’

% liquids: 78%

API Gravity: 52.4

Galvan Ranch C917H

IP30: 2,024 Boe/d

IP30 oil: 310 Bbl/d

Lateral Length: 7,886’

% liquids: 47%

API Gravity: 61.9

Galvan Ranch B904H

IP30: 3,452 Boe/d

IP30 oil: 887 Bbl/d

Lateral Length: 11,306’

% liquids: 58%

API Gravity: 53.5

Board of Directors is actively engaged in ESG oversight

Board composition includes: independent

chairman; 8 of 9 independent directors;

diversity of gender, race, geography, tenure

and expertise

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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 2019SM charitable contributions totaled approximately

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 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.

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Appendix

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TWO TOP-TIER AREAS OF OPERATION

1Q 2020 REALIZATIONS BY REGION

Midland Basin

South Texas Total

Production Volumes

Oil (MBbls) 5,932 415 6,347

Gas (MMcf) 9,931 16,570 26,501

NGL (MBbls) 3 1,599 1,602

Total (Mboe) 7,590 4,776 12,367

Revenue (in thousands)

Oil $276,136 $15,557 $291,693

Gas $11,334 $29,376 $40,710

NGL $58 $21,772 $21,830

Total $287,528 $66,705 $354,233

Expenses (in thousands)

LOE $47,950 $10,843 $58,793

Ad Valorem $5,727 $1,719 $7,445

Transportation $28 $38,411 $38,438

Production Taxes $13,627 $1,248 $14,875

Per Unit Metrics

Realized Oil Per Bbl $46.55 $37.45 $45.96

% of Benchmark - WTI 101% 81% 100%

Realized Gas per Mcf $1.14 $1.77 $1.54

0 % of Benchmark - NYMEX Henry Hub 58% 91% 79%

Realized NGL per Bbl $16.77 $13.62 $13.62

% of Benchmark - HART 99% 80% 80%

Realized Price per Boe $37.88 $13.97 $28.64

LOE per Boe $6.32 $2.27 $4.75

Transportation per Boe - $8.04 $3.11

Ad Valorem per Boe $0.75 $0.36 $0.60

Production Tax per Boe $1.80 $0.26 $1.20

Production Tax as % of Pre-hedge Revenue 4.7% 1.9% 4.2%

Production Margin per Boe $29.01 $3.04 $18.97

Benchmark Pricing

NYMEX WTI Oil ($/Bbl) $ 46.17

NYMEX LLS Oil ($/Bbl) $ 49.90

NYMEX Henry Hub Gas ($/MMBtu) $ 1.95

Hart Composite NGL ($/Bbl) $ 17.02

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

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WELLS DRILLED, FLOWING COMPLETIONS AND DUC COUNT

1Q 2020 ACTIVITY BY REGION

Wells Drilled Flowing Completions DUC Count(1)

Gross Net Gross Net Gross Net

Midland Basin

Sweetie Peck 5 4 5 5 6 5

RockStar 20 18 14 14 51 47

Midland Basin total 25 22 19 19 57 52

South Texas 3 3 1 1 23 23

Total 28 25 20 20 80 75

(1) As of March 31, 2020.

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)

Q2 2020 2,838 $58.81 1,881 $62.17 $55.00 3,637 ($0.62) 910 ($8.06) 600 ($2.37)

Q3 2020 3,361 $56.43 1,252 $62.90 $55.00 3,607 ($0.62) 920 ($8.01) 2,506 ($1.29)

Q4 2020 4,397 $57.03 610 $61.90 $55.00 4,087 ($0.38) 920 ($8.01) 2,552 ($1.29)

Q1 2021 2,200 $44.01 329 $56.70 $55.00 2,834 $0.86 900 ($7.86) 270 ($0.37)

Q2 2021 1,456 $37.57 - - - 2,922 $0.87 910 ($7.86) 273 ($0.37)

Q3 2021 1,765 $37.98 - - - 2,885 $0.87 920 ($7.86) 276 ($0.37)

Q4 2021 2,139 $38.53 - - - 2,886 $0.87 920 ($7.86) 276 ($0.37)

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

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

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

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

IF HSC Gas Swaps WAHA Gas Swaps

PeriodVolume

(BBtu)$/MMBtu(2) Volume

(BBtu)$/MMBtu(2)

Q2 2020 4,160 $2.20 3,838 $0.67

Q3 2020 4,493 $2.41 4,628 $1.08

Q4 2020 6,994 $2.32 4,872 $1.21

Q1 2021 8,148 $2.32 5,158 $1.52

Q2 2021 8,115 $2.32 4,525 $1.47

Q3 2021 9,371 $2.32 4,629 $1.47

Q4 2021 9,184 $2.32 4,722 $1.46

Q1 2022 1,632 $2.23 - -

Q2 2022 1,545 $2.23 - -

Q3 2022 1,497 $2.23 - -

Q4 2022 1,430 $2.23 - -

Ethane Propane

PeriodVolume

(MBbls)$/Bbl(2) Volume

(MBbls)$/Bbl(2)

Q2 2020 264 $11.13 382 $22.34

Q3 2020 - - 409 $22.33

Q4 2020 - - 466 $22.29

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BY QUARTER

OIL, GAS, AND NGL DERIVATIVE POSITIONS(1)

Oil

Gas NGLs

(1) Includes derivative contracts for settlement at any time during the second quarter of 2020 and later periods, entered into as of 4/28/2020.

(2) Weighted-average contract price.

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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 63,800

Midland Basin total 81,800

South Texas 158,900

Rocky Mountain Other 10,600

Other Areas / Exploration 26,400

Total 277,700

SOUTH TEXAS NET ACRES

~159,000

As of March 31, 2020

Net Acres(1)

(1) Includes developed and undeveloped oil and natural gas leasehold, fee properties, and mineral servitudes held as of March 31, 2020.

(2) Sweetie Peck acreage includes 1,940 net drill-to-earn acreage.

Differential reflects NGL composite

barrel product mix as well as

transportation and fractionation fees

NGL REALIZATIONS

17

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

SM Energy NGL Composition(1) 40%

29%

13%

9%

9%

Ethane

Isobutane

Natural Gasoline

Propane

Normal

Butane

(1) 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. During the first quarter of 2020, the Company rejected ethane, and expects to continue rejecting ethane for the second quarter.

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

Mont Belvieu Benchmark Price ($/Bbl) $26.28 $22.23 $18.89 $21.96 $17.02

SM NGL Realization ($/Bbl) $19.39 $16.42 $15.73 $17.84 $13.62

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

Realizations by Quarter

18

Non-GAAP Definitions & Reconciliations

19

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 first quarter 2020 Form 10-Q 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 in capital expenditure accruals and other.

Net debt: The total principal amount of outstanding senior 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.

Three Months Ended

March 31,

2020

(in thousands)

Net loss (GAAP) $ (411,895)

Net derivative gain (545,340)

Derivative settlement gain 73,437

Impairment 989,763

Gain on extinguishment of debt (12,195)

Other, net 386

Tax effect of adjustments(3) (109,813)

Valuation allowance on deferred tax assets 10,017

Adjusted net loss (non-GAAP) $ (5,640)

Diluted net loss per common share (GAAP) $ (3.64)

Net derivative gain (4.83)

Derivative settlement gain 0.65

Impairment 8.76

Gain on extinguishment of debt (0.11)

Other, net -

Tax effect of adjustments(3) (0.97)

Valuation allowance on deferred tax assets 0.09

Adjusted net loss (non-GAAP) $ (0.05)

Basic weighted-average common shares outstanding 113,009

Diluted weighted-average common shares outstanding 113,009

Three Months Ended

March 31,

2020

(in thousands)

Net loss (GAAP) $ (411,895)

Interest expense 41,512

Income tax benefit (99,008)

Depletion, depreciation, amortization, and asset retirement

obligation liability accretion233,489

Exploration(2) 10,392

Impairment 989,763

Stock-based compensation expense 5,561

Net derivative gain (545,340)

Derivative settlement gain 73,437

Gain on extinguishment of debt (12,195)

Other, net 333

Adjusted EBITDAX (non-GAAP) $ 286,049

Interest expense (41,512)

Income tax benefit 99,008

Exploration(2) (10,392)

Amortization of debt discount and deferred financing costs 3,992

Deferred income taxes (99,347)

Other, net (1,149)

Net change in working capital (18,517)

Net cash provided by operating activities (GAAP) $ 218,132

NON-GAAP RECONCILIATIONS

20

Adjusted EBITDAX(1) Adjusted Net Loss(1)

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

(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-month period ended March 31, 2020. This rate approximates the Company’s statutory tax rate adjusted for ordinary permanent differences.

Three Months Ended

March 31,

2020

(in thousands)

Senior Notes (principal amount - Note 5 of 1Q20 Form 10-Q) $ 2,436,047

Senior Convertible Notes (principal amount - Note 5 of 1Q20

Form 10-Q)172,500

Revolving credit facility 72,000

Total funded debt $ 2,680,547

Less:

Cash and cash equivalents 15

Net debt $ 2,680,532

Three Months Ended

March 31,

2020

(in thousands)

Net cash provided by operating activities (GAAP) $ 218,132

Net change in working capital 18,517

Cash Flow from Operations before net change in working capital 236,649

Exploration(3) 10,392

Discretionary cash flow (Non-GAAP) $ 247,041

Capital expenditures (GAAP) $ 139,306

Changes in capital expenditure accruals and other 16,802

Capital expenditures before increase in capital expenditure accruals and other 156,108

Capitalized interest (2,692)

Exploration(3) 10,392

Other 662

Total capital spend (Non-GAAP) $ 164,470

Free cash flow (old method) $ 82,571

Capitalized interest (2,692)

Other 662

Free cash flow (new method) $ 80,541

NON-GAAP RECONCILIATIONS

21

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

(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 first quarter 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.

RECONCILIATION OF PRIOR CALCULATION METHOD TO NEW METHOD

Free Cash Flow(1)(2)

Net Debt(1)

Vice President - Investor Relations

303.864.2507

jsamuels@sm-energy.com

CONTACT INFORMATION

22

Jennifer Martin Samuels