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1 May 2017 Investor Presentation PREMIER OPERATOR OF TOP TIER ASSETS

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1

May 2017Investor Presentation

PREMIER OPERATOR OF TOP TIER ASSETS

Please Read This presentation makes reference to:

Forward-looking statements

This presentation contains forward-looking statements within the meaning of securities laws. The words “anticipate,” “assume,” “believe,”

“budget,” “estimate,” “expect,” “forecast,” “guidance,” “intend,” “plan,” “project,” “will” and similar expressions are intended to identify forward-

looking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from

results expressed or implied by the forward-looking statements. Forward-looking statements in this presentation include, among other things,

2017 guidance, expectations regarding growth strategy, consummation of pending transactions, anticipated drilling plans and capital

expenditures, anticipated growth in cash flows, the expected benefits, financing sources and timing of acquisitions, and the expected benefits

and likelihood of completing divestitures. General risk factors include the uncertain nature of acquisition, divestiture, joint venture, farm down or

similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected

acquisition, divestiture, joint venture, farm down or similar efforts; the uncertainty of negotiations to result in an agreement or a completed

transaction; the availability of and access to capital markets; the availability, proximity and capacity of gathering, processing and transportation

facilities; the volatility and level of oil, natural gas, and natural gas liquids prices, including any impact on the Company’s asset carrying values

or reserves arising from price declines; uncertainties inherent in projecting future rates of production or other results from drilling and completion

activities; the imprecise nature of estimating oil and gas reserves; uncertainties inherent in projecting future drilling and completion activities,

costs or results, including from pilot tests; the availability of additional economically attractive exploration, development, and acquisition

opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and

development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the

Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other

such matters discussed in the “Risk Factors” section of SM Energy's 2016 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. In addition, production forecasts

and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells

and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost

increases. The forward-looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to

time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except as required by securities laws.

2

Non-GAAP financial measures: See appendix for reconciliations

Note: slide deck changes (slides 5,6, and 8) include impact of increased

production and cash flow to 3-year plan.

3

Midland BasinSweetie Peck/RockStar

~88,000 net acres

Maverick BasinEagle Ford

~167,000 net acres

SM Energy 3-Year Plan Focused on Two Core Assets

3

Top tier oil in Midland + top tier NGLs and gas in Eagle Ford

Successful transformation to core up portfolio

4

SM Energy A Premier Operator of Top Tier Assets

3 Year Plan Expected

Outcomes:

Big growth in

high-margin

production

Big growth in

cash flow

Debt:EBITDAX

~2x in 2019

Top Tier

portfolio

5

Big Expected Production Growth

0%

10%

20%

30%

40%

50%

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2016 2017 2018 2019

Oil %

Pro

du

cti

on

(MB

oe

)

Midland Basin Operated Eagle Ford Rockies Revised Guidance Sold Oil %

(e) (e) (e)

~100% CAGR Midland Basin

Adjusted 3-year plan(1)

(1) Adjusted for increased production guidance provided on 5/3/17 and retention of Divide County assets.

(2) Sold production relates to the Non-operated Eagleford, Williston, and Southeast New Mexico divestitures. Note that the initial version of this slide posted on 5/16/17 only

included the Non-operated Eagle Ford divestiture in the sold category.

(2)

6

Big Cash Flow Growth Driven by Expected Margin Expansion

Operating margin expected to increase 80% 4Q16 – 2019

Production growth expected within cash flow in 2019

Adjusted plan results in increased cash flow, decreased outspend

Note: Based on strip pricing as of 2/3/17.

(1) Adjusted for increased production guidance provided on 5/3/17 and retention of Divide County assets.

(2) Realized price before the effect of hedges less LOE, transportation, production taxes, and G&A.

Cash Flow Expected to Double 2017 - 2019

$10

$13

$16

$19

$22

$25

$0

$650

$1,300

4Q16 2017 2018 2019

Op

era

tin

g M

arg

in$

/Bo

e

Ca

sh

Flo

w$

/MM

Cash Flow Operating Margin

(e)

Adjusted 3-year plan(1)

(e) (e)

(2)

Financial Discipline Strengthening the Balance Sheet

7

On track with 2017 financial strategy

Other

86% 8%

Drilling and

Completion

86%

Facilities

6%

Other

8%

(1)

• Liquidity of $1.6 billion (as of March 31, 2017)

• $747 million net cash proceeds from non-operated Eagle Ford sale March 2017

• Net debt reduced to $2.3 billion; reduced 22% 1Q17/4Q16

• No bond maturities until 2021; 2021 notes currently callable; 2023 notes callable July 2017

• Coverage metrics provide flexibility; March 31, 2017:

• Senior Secured Debt:TTM Adjusted EBITDAX at ~0.0 times; max ratio allowed 2.75 times

• TTM Adjusted EBITDAX:Interest at ~4.5 times; minimum ratio required 2.0 times

$500$500$500$395

$562

$345

$172.5

$0

$250

$500

$750

$1,000

2026202520242023202220212020201920182017

Debt Maturities as of March 31, 2017(in millions)

~$0 drawn

Commitments and Borrowing

base $925 million (as of 3/31/17)

Corporate ratings: S&P BB-, Moody’s B1

Coupon 1.500%

6.500%

6.125% 6.500% 5.000% 5.625% 6.750%

3-Year Plan Prefunded by Cash Flow and Divestiture

8

Proceeds from non-operated Eagle Ford sale > 2017-2018 expected outspend

Other

86% 8%86%

Facilities

6%

Other

8%Midland

Basin

80%

(2)(1)

2017

Outspend

2018

Outspend

Non-operated

Eagle Ford

sale

2017 – 2018

Projected

Outspend

• Additional cash flows from retention of Divide County assets reduce

2017-2018 expected outspend

• 3-year plan objective of Net Debt : EBITDAX ~2.0x

Note: Based on strip pricing as of 2/3/17.

Financial Discipline Hedging Provides Cash Flow Stability

9

• ~75% of expected 2017 production volumes hedged (at the midpoint of guidance)

• ~ 70% of oil, 80% of natural gas and 80% of NGLs

• Approximately 1/2 of expected 2018 volumes hedged

0

1

2

3

4

5

6

7

8

9

10

2Q17 3Q17 4Q17

(MM

BO

E)

Hedged Volumes as of April 26, 2017

Oil Gas NGLs

Credit Agreement modified to allow hedging of up

to 85% of 2017-2019 projected production

Note: The hedged volumes on this slide do not include any volumes related to basis swaps.

SM Energy A Premier Operator of Top Tier Assets

2017 Priorities:

Complete

portfolio

transition

Focus capital

on drivers of

value creation

Midland Basin

development

acceleration

Strong

balance sheet

and liquidity

10

Midland Basin Setting Up for Expanded 2018 Program

11

Excellent vendor relationships and continued improvements in operating efficiencies

set the stage for expansion in 2018

Significant experience

in the basin - strong

vendor relationships

Sufficient takeaway

capacity

Sufficient water

availability to run program

Continued performance

improvement

Midland Basin 1Q17

12

Midland Basin~88,000 net acres

Sweetie Peck

RockStar

Halff East

Ramping up quickly – setting up for 2018

• 6 horizontal rigs and 1 data

gathering rig; 3 completions crews

active

• Production up 55% sequentially;

RockStar wells significantly

outperforming acquisition

assumptions

• Drilled 20(1) 10,000’ laterals to date

and added 1,300 net acres of

adjacent land positions

• Program actively testing Wolfcamp

A, Wolfcamp B, and Lower

Spraberry

(1) Includes four wells drilled by previous operator and completed by SM.

Midland Basin Premier Operator

13

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

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

Cum

ula

tive P

roduction (

BO

E)

Days

VENKMAN 26-35 A #15WA VENKMAN 26-35 B #1 WA

Applying technology to optimize development

• Acquiring core and log data

Steering to best zones

Identifying new pay intervals

• Enhancing completion designs

• Swapping and acquiring adjacent

land positions: more long laterals

• Gaining efficiencies through intensive

pad drilling

• Using ‘Digital Oilfield’ to improve well

uptime statistics

Example: Venkman wells in RockStar Area

Improved

Completion

Design

• Optimized completion design in two

Wolfcamp A wells in same spacing unit

• Result: More than 60% improvement in

120 day cumulative oil production

(completed by previous operator)

7,700’ lateral7,430’ lateral

14

Howard County Significant Increase in Activity

Industry confidence drives increased drilling activity across the county

January 2017: 18 Rigs April 2017: 28 Rigs

15

Howard County Positive Peer Well Results

Peer wells extend “confirmed” geologic assessment to east and south

Tubb A 1HA

Thumper 14-23

• Thumper 14-23

• 7,500’ lateral

• 24-hour rate: 1,357 Boe

(91% oil)

• Tubb A 1HA

• 9,366’ lateral

• produced 141,000 Boe

over 132 days

Source: Tubb A 1HA well data courtesy of Earthstone Energy Inc.

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

220,000

240,000

0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320

Gro

ss

Cu

mu

lati

ve

Pro

du

cti

on

(B

OE

)

Production Days

1 MMBOE Peer Type Curve 20% IRR Type Curve

RockStar Top Tier Well Performance Continues

16

Initial production rates on SM completed wells soundly beating acquisition assumptions

Note: Well economics at $50 oil and $3.00 gas; monthly data normalized to days on production.

* Peer Type Curve adjusted to meet 20% IRR

SM Operated Well

RockStar wells average ~90% oil at ~40 API gravity

Howard County Recent Well Results

Recent wells targeting three intervals: Wolfcamp A, Wolfcamp B, and Lower Spraberry

17

Well Name Interval

Lateral

Length

IP Rate

(BOE/d)

IP

Days

Tackleberry 43-42 A 1LS LS 7,873’ 1,286 30

Tackleberry 43-42 A 1WA WCA 7,861’ 2,262 30

Tackleberry 43-42 A 2WB WCB 7,885’ 1,412 30

Rambo 3846WA(4) WCA 7,546’ 1,130 30

Rambo 3848WA(5) WCA 7,590’ 1,118 30

Venkman 26-35 B 1WA WCA 7,700’ 1,274 30

Top Gun 1632LS(6) LS 7,711’ 1,236 30

Top Gun 1652WA(7) WCA 7,595’ 1,655 30

(1) Name changed from Corrine Elizabeth 26-27 A 1H (4) Name changed from Rambo 38-47 7WA (7) Name changed from Top Gun 1H

(2) Name changed from Corrine Elizabeth 26-27 A 2H (5) Name changed from Rambo 38-47 9WA

(3) Name changed from Corrine Elizabeth 26-27 A 3H (6) Name changed from Top Gun 2H

Well Name Interval

Lateral

Length

IP Rate

(BOE/d)

IP

Days

Guitar North 2722LS(1) LS 9,692 1,093+ 20

Guitar North 2742WA(2) WCA 9,698 1,981 20

Guitar North 2762WB(3) WCB 9,693 1,693 20

1Q17 Wells

4Q16 Wells

Note: Guitar North 2722LS 20-day IP Rate still climbing

0

10

20

30

40

50

0 30 60 90 120 150 180 210 240 270

Gro

ss C

um

ula

tive P

roduction (

BO

E/F

T)

Production Days

Eagle Ford Increasing Value With More Wells Per Section

18

900’ East Type Curve

(LEF) – BOE/FT

All three areas support UEF/LEF co-development

6 Wells (A)

11 UEF/LEF

Co-Development

wells

4Q16

Completions

Operated Eagle Ford – Recent Well Results

2015/2016 East Area co-development

4Q 2016 East Area co-development (A)

1Q 2017 North Area co-development

South

Area

North

AreaEast

Area

East 4Q16 Completions

Continued Outperformance

at 312’ plan view spacing

1Q17

Completions

Note: 2-stream data; does not reflect ~70

Bbls/MMcf NGL yield for type curve shown.

19

SM Energy A Premier Operator of Top Tier Assets

3 Year Plan Expected Outcomes:

Big growth in

high-margin

production

Big growth in

cash flowDebt:EBITDAX

~2x in 2019

2017 Priorities:

Complete

portfolio

transition

Focus capital

on drivers of

value creation

Midland Basin

development

acceleration

Top Tier

portfolio

Strong

balance sheet

and liquidity

20

Appendix

0%

20%

40%

60%

80%

100%

120%

$40 $45 $50 $55 $60

IRR

NYMEX WTI

7,600' 10,000'

0%

20%

40%

60%

80%

100%

120%

$40 $45 $50 $55 $60

IRR

NYMEX WTI

7,600' 10,000'

0%

20%

40%

60%

80%

100%

$0.60 $0.65 $0.70

IRR

Mt. Belvieu $/Gal

Regional Well Projected Economics

21

2017 capital program focusing on areas with top tier returns

RockStar – Wolfcamp A

Well Cost: $5.6MM

Well Spacing: 660’Well Cost: $6.8MM

Well Spacing: 660’Well Cost: $5.9MM

Well Spacing: 660’

Well Cost: $7.0MM

Well Spacing: 660’

Sweetie Peck – Lower Spraberry

Note: well costs include drill, complete, and equip; sensitivities at $3.00/MMBtu NYMEX; Eagle Ford East oil flat at $50/Bbl WTI

Eagle Ford East

Well Cost: $5.2MM, Lateral Length: 8,000’, Well Spacing: 625’, Sand Loading: 2,000 lbs/ft, Stage Spacing: 150’

Sand loading: 1,900 lbs/ft; Stage Spacing: 167’ Sand loading: 1,900 lbs/ft; Stage Spacing: 167’

Eagle Ford East

~35% NGLs

1Q17 Average

Mt. Belvieu ($/Gal)

1st Quarter 2017 Performance

22

Production 1Q17

Total Production (MMBoe) 12.1

Average Daily Production (MBoe/d) 134.4

Pre-Hedge Realized Price ($/Boe) $27.55

Post-Hedge Realized Price ($/Boe) $27.55

Costs

LOE ($/Boe) $3.82

Ad Valorem ($/Boe) $0.55

LOE including Ad Valorem ($/Boe) $4.37

Transportation ($/Boe) $5.88

Production Taxes (% of pre-derivative oil, gas & NGL revenue) 4.2%

Total Cash Production Expenses $11.42

Production Margin (pre-hedge) $16.13

G&A – Cash ($/Boe) $2.08

G&A – Non Cash ($/Boe) $0.34

Total G&A ($/Boe) $2.42

DD&A ($/Boe) $11.39

1Q17 Regional Realizations

23

Pricing

NYMEX WTI Oil ($/Bbl) $51.91

NYMEX LLS Oil ($/Bbl) $53.39

NYMEX Henry Hub Gas ($/MMBTU) $3.32

Hart Composite NGL ($/Bbl) $26.74

Production Volumes Eagle Ford Op(1) Rocky Mountain Permian

Eagle Ford

Non-Op(2) SM Total

Oil (MBbls) 421 999 1,623 483 3,525

Gas (MMcf) 26,936 1,026 2,882 3,052 33,895

NGL (MBbls) 2,404 36 6 474 2,921

MBOE 7,315 1,206 2,109 1,465 12,095

Expenses (in thousands)

LOE $13,420 $11,785 $16,328 $4,629 $46,162

Ad Valorem 3,172 32 2,174 1,285 6,663

Transportation 58,366 2,288 116 10,323 71,093

Production Taxes 3,389 4,974 4,617 1,148 14,128

Revenue (in thousands)

Oil $17,324 $47,261 $81,499 $21,540 $167,624

Gas 77,983 1,641 11,309 10,218 101,151

NGL 53,152 919 147 10,205 64,423

Total $148,459 $49,821 $92,955 $41,962 $333,198

Note: Totals may not sum due to rounding and other classifications

(1) Includes nominal amounts of other production and expenses from the region

(2) The Eagle Ford Non-Op divestiture closed on March 10, 2017

Per Unit Metrics:

Realized Oil/Bbl $41.13 $47.33 $50.22 $44.61 $47.55

% of Benchmark - WTI 79% 91% 97% 86% 92%

Realized Gas/Mcf $2.90 $1.60 $3.92 $3.35 $2.98

% of Benchmark – NYMEX HH 87% 48% 118% 101% 90%

Realized NGL/Bbl $22.11 $25.19 $24.15 $21.54 $22.06

% of Benchmark – HART 83% 94% 90% 81% 82%

Realized BOE $20.30 $41.31 $44.07 $28.64 $27.55

LOE/BOE $1.83 $9.77 $7.74 $3.16 $3.82

Ad Val/BOE $0.43 $0.03 $1.03 $0.88 $0.55

Transportation/BOE $7.98 $1.90 $0.06 $7.05 $5.88

Production Tax - % of

Pre-Hedge Revenue

2.3% 10.0% 5.0% 2.7% 4.2%

2017 Activity Wells Drilled, Flowing Completions & DUC Count

24(1) Activity in the Powder River Basin is funded entirely through a carry arrangement with a third party.

Wells Drilled Flowing Completions DUC Count

1st Quarter 2017 1st Quarter 2017 1st Quarter 2017

Region Gross Net Gross Net Gross Net

Permian

Sweetie Peck 7 7 11 11 7 7

RockStar 12 12 5 5 13 13

Permian total 19 19 16 16 20 20

Eagle Ford (operated) 5 5 17 17 35 35

Rocky Mountain

Divide County - - - - 20 17

Powder River Basin(1) 3 - 1 - 3 -

Rocky Mountain total 3 - 1 - 23 17

Subtotal Operated Wells 27 24 34 33 78 72

Non-operated Wells n/a 2 n/a - n/a 2

Total n/a 26 n/a 33 n/a 74

Leasehold Summary

25

As of March 31, 2017

Net Acres(1)

3/31/17

Midland Basin

Sweetie Peck(2) 15,880

Halff East (Upton County) 5,985

RockStar 66,195

Eagle Ford

Operated 166,760

Rocky Mountain

Divide 123,570

Powder River Basin 156,260

Rocky Mountain Other(3) 190,330

Other Areas/Exploration 24,915

Total 749,895

(1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of March 31, 2017. RockStar

acreage includes approximately 900 net acres related to transactions that closed subsequent to March 31, 2017.

(2) Sweetie Peck acreage includes 1,480 net acres of drill-to-earn acreage.

(3) Rocky Mountain Other includes non-core acreage located in North Dakota, Montana, Wyoming, and Utah.

Adjusted EBITDAX Reconciliation

26

Reconciliation of net income (GAAP) to Adjusted EBITDAX (non-GAAP) to

net cash provided by operating activities (GAAP): (in thousands)

Three Months Ended

March 31, 2017Net income (GAAP) $74,434

Interest expense 46,953

Other non-operating income, net (335)

Income tax expense 44,506

Depletion, depreciation, amortization, and asset retirement obligation liability accretion 137,812

Exploration(1) 10,570

Stock-based compensation expense 5,455

Net derivative gain (114,774)

Derivative settlement gain 7

Net gain on divestiture activity (37,463)

Loss on extinguishment of debt 35

Other 4,986

Adjusted EBITDAX (Non-GAAP) 172,186

Interest expense (46,953)

Other non-operating income, net 335

Income tax expense (44,506)

Exploration(1) (10,570)

Amortization of discount and deferred financing costs 4,946

Deferred income taxes 33,225

Plugging and abandonment (1,191)

Other, net (432)

Changes in current assets and liabilities 27,926

Net cash provided by operating activities (GAAP) $134,966

Note: Adjusted EBITDAX represents net income (loss) before interest expense, other non-operating income and expense, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration

expense, property impairments, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, gains and losses on divestitures, gains or losses on extinguishment of debt, and

materials inventory impairments and losses on sale. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing

and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes it provides useful additional information to investors and analysts, as a performance measure, for

analysis of the Company's ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to financial covenants under its Credit Agreement based on adjusted EBITDAX ratios. In

addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the

published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating

activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be

comparable to similar metrics of other companies. Under the terms of the Company’s credit agreement, if the Company fails to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a

minimum permitted ratio of adjusted EBITDAX to interest, it will be in default, an event that would prevent it from borrowing under its credit facility and would therefore materially limit the Company’s sources of liquidity. In addition, if the Company was

in default under its credit facility and unable to obtain a waiver of that default from its lenders, the lenders under that facility and under the indentures governing the Company’s outstanding Senior Notes and Senior Convertible Notes would be entitled

to exercise all of their remedies for a default.

(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the

exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based

compensation expense recorded to exploration expense.

Adjusted Net Loss Reconciliation

27

Note: Adjusted net income (loss) excludes certain items that the Company believes affect the comparability of operating results. Items excluded generally are non-recurring items or are items

whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as derivative gains and losses net of settlements, gains and losses

on divestiture activity, and materials inventory loss. The non-GAAP measure of adjusted net loss is presented because management believes it provides useful additional information to

investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that adjusted net loss is widely used by professional research analysts and

others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of

industry research analysts in making investment decisions. Adjusted net loss should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, cash

provided by operating activities, or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net loss excludes some, but not all, items that affect net

income (loss) and may vary among companies, the adjusted net income (loss) amounts presented may not be comparable to similarly titled measures of other companies.

(1) Income taxes are calculated using a tax rate of 36.1%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. The rate is applied to the adjustments made in calculating adjusted net loss.

(2) For periods where the Company reports net income (GAAP) and adjusted net loss (non- GAAP), basic weighted-average common shares outstanding are used in the calculation of adjusted net loss per diluted common share.

Reconciliation of net income (GAAP) to adjusted net loss (non-GAAP):

(in thousands, except per share data)

Three Months Ended

March 31, 2017Net income (GAAP) $74,434

Net derivative gain (114,774)

Net gain on divestiture activity (37,463)

Other, net 5,028

Tax effect of adjustments(1) 53,142

Adjusted net loss (Non-GAAP) $(19,633)

Diluted net income per common share (GAAP) $0.67

Net derivative gain (1.03)

Net gain on divestiture activity (0.34)

Other, net 0.04

Tax effect of adjustments(1) 0.48

Adjusted net loss per diluted common share (Non-GAAP)(2) $(0.18)

Basic weighted-average common shares outstanding: 111,258

Diluted weighted-average common shares outstanding: 111,329

Total Capital Spend Reconciliation

28

Reconciliation of Costs Incurred in Oil and Gas Activities (GAAP)

to Total Capital Spend (Non-GAAP)(1) (in millions)

Three Months

Ended

March 31, 2017

Costs incurred in oil and gas activities (GAAP): $281.5

Less: Asset retirement obligation (0.9)

Less: Capitalized interest (2.2)

Less: Proved property acquisitions(2) (2.2)

Less: Unproved property acquisitions(3) (83.6)

Less: Other 0.3

Total capital spend (Non-GAAP): $192.9

(1) The non-GAAP measure of total capital spend is presented because management believes it provides useful information to investors for analysis of

SM Energy's fundamental business on a recurring basis. In addition, management believes that total capital spend is widely used by professional

research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and

production industry, and many investors use the published research of industry research analysts in making investment decisions. Total capital spend

should not be considered in isolation or as a substitute for Costs Incurred or other capital spending measures prepared under GAAP. The total capital

spend amounts presented may not be comparable to similarly titled measures of other companies.

(2) Includes approximately $800,000 of ARO associated with proved property acquisitions for the three month period ended March 31, 2017.

(3) Includes approximately $24.5 million related to the fair value attributed to the properties surrendered in the non-monetary acreage trade that

completed during the three-month period ended March 31, 2017.

Derivative Positions Summary By Quarter Through 2018

29

As of April 26, 2017

Period

Volume

(MBbls) $/Bbl(1)

Volume

(BBTU) $/MMBTU(1)

Volume

(MBbls) $/Bbl(2)

2Q’17 1,444 $46.44 26,205 $3.98 2,114 $21.40

3Q’17 1,340 $46.66 23,657 $4.01 2,019 $20.89

4Q’17 1,254 $46.35 22,001 $3.98 1,996 $20.18

1Q’18 - - 19,628 $3.25 1,828 $21.45

2Q’18 - - 13,052 $2.85 1,438 $16.26

3Q’18 - - 14,241 $2.87 1,414 $16.53

4Q’18 - - 15,487 $2.90 1,416 $16.72

Period

Volume

(MBbls)

Ceiling

$/Bbl(1)

Floor

$/Bbl(1)

2Q’17 636 $54.10 $45.00

3Q’17 583 $54.05 $45.00

4Q’17 1,086 $56.05 $47.51

1Q’18 1,026 $58.46 $50.00

2Q’18 1,004 $58.37 $50.00

3Q’18 1,393 $57.93 $50.00

4Q’18 1,607 $57.75 $50.00

Fixed Swaps

Collars

Oil

Oil

Gas NGL(3)

(1) Prices are weighted averages; natural gas prices reflect the weighted average of regional contract positions and are no longer adjusted to a NYMEX equivalent.

(2) Weighted Average Price – Mont Belvieu

(3) NGL derivative positions include propane, ethane, gasoline, and butanes.

Note: Includes all commodity derivative contracts for settlement at any time during the second quarter of 2017 and later periods through 2018, entered into as of 4/26/17.

Period

Volume

(MBbls)Price Differential

$/Bbl(1)

2Q’17 - -

3Q’17 566 ($1.62)

4Q’17 1,403 ($1.55)

1Q’18 1,075 ($1.40)

2Q’18 1,371 ($1.42)

3Q’18 1,609 ($1.43)

4Q’18 1,609 ($1.43)

Midland – Cushing Oil Basis Swaps

NGL Derivative Position Detail(1)

30

Period

Volume

(MBbls) $/Bbl(2)

2Q’17 892 $9.11

3Q’17 906 $9.48

4Q’17 966 $9.65

2017 Total 2,764

1Q’18 923 $10.90

2Q’18 915 $10.87

3Q’18 878 $10.76

4Q’18 875 $10.82

2018 Total 3,591

NGL Swaps OPIS Eth Purity Mt Belv NGL Swaps OPIS Propane Mt Belv Non-TET NGL Swaps Natural Gasoline Mt Belv Non TET

NGL Swaps OPIS IsoButane Mt Belv Non TETNGL Swaps OPIS NButane Mt Belv Non TET

(1) Includes all commodity derivative contracts for settlement at any time during the second quarter of 2017 and later periods through 2018 entered into as of April 26, 2017.

(2) Weighted-Average Contract Price

Note: Totals may not sum due to rounding; reference 10-Q for future period detail

Period

Volume

(MBbls) $/Bbl(2)

2Q’17 249 $48.47

3Q’17 222 $48.43

4Q’17 203 $48.41

2017 Total 675

1Q’18 189 $49.40

2Q’18 35 $47.36

3Q’18 39 $47.36

4Q’18 42 $47.36

2018 Total 305

Period

Volume

(MBbls) $/Bbl(2)

2Q’17 182 $32.53

3Q’17 163 $32.42

4Q’17 149 $32.34

2017 Total 493

1Q’18 138 $35.41

2Q’18 26 $31.71

3Q’18 29 $31.71

4Q’18 32 $31.71

2018 Total 225

Period

Volume

(MBbls) $/Bbl(2)

2Q’17 634 $21.90

3Q’17 588 $21.91

4Q’17 550 $21.91

2017 Total 1,772

1Q’18 460 $23.35

2Q’18 440 $23.38

3Q’18 446 $23.55

4Q’18 442 $23.64

2018 Total 1,787

Period

Volume

(MBbls) $/Bbl(2)

2Q’17 157 $33.38

3Q’17 140 $33.28

4Q’17 128 $33.23

2017 Total 425

1Q’18 119 $35.44

2Q’18 21 $30.35

3Q’18 23 $30.35

4Q’18 25 $30.35

2018 Total 188

NGL Realizations

31

• Nearly 90% increase in realized price (before hedges) from 1Q16 to 1Q17

• SM NGL price realizations are predominately tied to Mont Belvieu, fee based contracts

• Differential reflects NGL barrel product mix and transportation and fractionation fees

1Q16 2Q16 3Q16 4Q16 1Q17

Mt. Belvieu ($/Bbl) $15.99 $20.04 $19.74 $24.11 $26.74

SM Realization

($/Bbl)$11.76 $16.12 $16.58 $20.02 $22.06

% Differential to

Mt. Belvieu74% 80% 84% 83% 82%

42%

28%

9%

9%

12%

SM Typical NGL Bbl(1)

Ethane PropaneIso Butane Normal ButanePentane

(1) Includes the effects of ethane rejection.

2017 Capital Program

32

Aggressive growth expected in the Midland Basin

Total Capital Budget ~$875MM

Other

86% 8%

Drilling and

Completion

86%

Facilities

6%

Other

8%Midland

Basin

80%

Operated Eagle

Ford

20%

• Average 7 rigs

• ~$750MM drilling and completion budget

• Planning more than 115 gross completions

(2)

(1) Approximately 10% of the drill and complete budget is related to non-operated assets, primarily in the Midland Basin.

(2) Other includes exploration and allocated overhead.

(1)

Setting Up for Expanded 2018 Program

33

Excellent vendor relationships and continued improvements in operating efficiencies

set the stage for expansion in 2018

• Use multiple contractors

• Eagle Ford: Rigs and frac crews contracted through year-end, sand volumes

and prices predominantly locked-in through year-end

• Midland Basin: Rigs and frac crews contracted through year-end with 7th rig;

vendors competing for market share

Significant

experience in

the basin –

strong vendor

relationships

Sufficient

takeaway

capacity

• Current oil pipeline takeaway 2.7 MMBbl/d vs. 2Q17(e) at 2.4 MMBbl/d

• Additional planned oil takeaway adds more than 650 MBbl/d by early 2018

Sufficient water

availability to

run program

• Sufficient water rights acquired to meet plan needs

• Saltwater disposal wells included in capital spend budget

• Sand supply companies adding significant capacity

Continued

performance

improvement

• RockStar drilling performance improved 25% in two months; one 7,500’ lateral

drilled in under 10 days

• Geosteering - placing laterals over 95% in zone, faster penetration rates

34

Excellent proximity to gathering/processing and takeaway with significant capacity

Midland Basin Infrastructure

Oil• 100% sold at wellhead

• 65% on pipeline (35% trucked)

• Currently working toward 100%

on pipeline

Gas• 100% sold at wellhead

• 100% third party gathered

NGLs• 100% sold at wellhead

• 100% third party gathered

• Current oil takeaway of 2.7 MMBbl/d vs. estimated 2Q17 oil production of 2.4 MMBbl/d

• Permian providers currently keeping up with growth – expected additional oil pipeline takeaway adds more than 650 MBbl/d by early 2018

• SM has sufficient water availability to meet plan needs

• SM anticipates adding SWDs (in SM capital spend budget)

Howard County Operators

35

SM Energy

Callon

Encana

Surge/Yantai Xinchao

Diamondback

Oxy

Energen

Breitburn

Sabalo

Sweetie Peck Operators

36

SM Energy

Apache

Chevron

Concho

Devon

Diamondback

Discovery

Endeavor

Exxon

Legacy

Oxy

Pioneer

Summit

Miscellaneous

Eagle Ford Operators

37

APC

APCAPC

APC

APC

CHK

CHK

NBL (ROSE)

SN

Lewis

SFY

SM EF North

SM EF South

SM EF East

Dimmit

38

Contact Information

Jennifer Martin SamuelsSenior Director, Investor Relations [email protected]