JUNE 2018 INVESTOR PRESENTATION PLEASE READ THIS PRESENTATION - - PowerPoint PPT Presentation

JUNE 2018 INVESTOR PRESENTATION

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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,” “pending,” “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, expected Permian Basin production, expectations about future cost inflation, and the expected benefits from joint venture arrangements. General risk factors include the availability

• f 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 natural gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results, including from pilot tests; the uncertainty of negotiations to result in an agreement or a completed transaction; uncertainties inherent in projecting the timing and ultimate outcome of litigation; the uncertain nature of acquisition, divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions; the uncertain nature

• f expected benefits from the actual or expected acquisition, divestiture, drilling carry, farm down or similar efforts; 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 2017 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. 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.

Non-GAAP financial measures: See Appendix for reconciliations Non-GAAP forward looking metrics: See Appendix for definitions

SM ENERGY PREMIER OPERATOR OF TOP TIER ASSETS

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FOCUSED ON TWO BASINS IN TEXAS

~35%

MIDLAND BASIN ▪ ~82,500 net acres ▪ 8 Rigs / 4 Frac Crews EAGLE FORD ▪ ~165,000 net acres ▪ 2 Rigs / 1 Frac Crew

• Market capitalization: ~$3.0B(1)
• Production: ~113 MBoe/d; 42%
• il, 41% natural gas, 17%

NGLs (1Q18)

• Proved Reserves: 468 MMBoe;

46% proved developed (YE17)

• Expected 2018 Capital Spend:

$1.27 billion

(1) As of May 31, 2018

(1) See Appendix for Cash Flow per Debt Adjusted Share definition (2) Betty Jiang and William Featherston, Credit Suisse

2017-2019 DRIVING DIFFERENTIAL VALUE

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OFF TO A GREAT START IN 2018

~35%

PREMIER OPERATOR TOP TIER ASSETS

~35%

C A G R 2 0 1 7 - 1 9 E x p e c t e d

CASH FLOW GROWTH

PER DEBT ADJUSTED SHARE(1) “CASH FLOW GROWTH PER DEBT ADJUSTED SHARE IS THE METRIC WITH THE HIGHEST CORRELATION TO INTRA SECTOR RELATIVE PERFORMANCE”

– Credit Suisse 12/11/17(2)

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FIRST QUARTER 2018 HIGHLIGHTS

Cash flow growth, up 30% sequentially

• Rapid margin expansion, highest in 14 quarters
• Big Midland production growth

Operational execution: New wells outperforming expectations

• 19 new RockStar wells average 1,440 Boe/d peak

30-day IP rates (88% oil) Significant reduction in net debt

• Non-core asset sales year-to-date reduce net debt and

core up portfolio

$792 million $1.6 billion

Non-core asset sales(1) Liquidity(2)

(1) Non-core asset sales in the Powder River Basin, North Dakota and Texas completed through May 2018 (2) As of March 31, 2018; commitment amount as of May 30, 2018

MIDLAND BASIN

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EXECUTING ON OUR PLAN Midland Basin

~82,500 net acres

RockStar Sweetie Peck

• 17 net completions in 1Q18
• 15 in RockStar area
• 8 rigs currently
• 4 frac fleets operating at high

efficiency

• ~36 net completions expected in

2Q18

• Focusing on co-development of

intervals

MIDLAND BASIN TOP WELL RESULTS

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SM RANKS #1 IN REVENUE PER WELL & REVENUE PER LATERAL FOOT(1)

(1) Baird Equity Research 3/28/18 – Joseph Allman

2017-2019 PERMIAN HIGH RATE OF CHANGE

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EXPECTED BIG PERMIAN PRODUCTION GROWTH & MARGIN EXPANSION

4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18e 3Q18e 4Q18e

Production (MBoe)

Note: 2018 estimated Permian Basin production by quarter based on February 2018 plan, updated for Halff East divestiture.

• Permian projected production growth up ~135% 2017-2019
• Company projected cash operating margin up over 45% 2017-2019

ROCKSTAR NEW WELL RESULTS

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GREAT RESULTS IN MULTIPLE INTERVALS ACROSS ACREAGE POSITION NEW WELLS AVERAGE 1,440 BOE/D, 88% OIL (10,200’ LATERAL LENGTH)

Wiley Bob A 2351WA Wiley Bob 2352WA(1) Guitar North 2850WA Guitar North 2851WA Guitar North 2852WA Guitar North 2867WB Guitar North 2868WB Berlinda Ann 2341WA Berlinda Ann 2342WA Berlinda Ann 2361WB Whitaker 22-27 Unit 2251WA Whitaker 22-27 Unit 2252WA Lumbergh 2547WA Lumbergh 2548WA Lumbergh 2565WB

30 Day Avg Peak Rate:

1,607 Boe/d (87% oil)

30 Day Avg Peak Rate:

1,623 Boe/d (85% oil)

30 Day Avg Peak Rate:

1,305 Boe/d (90% oil)

Lumbergh 2527LS Lumbergh 2528LS

30 Day Avg Peak Rate:

1,485 Boe/d (87% oil)

30 Day Avg Peak Rate:

941 Boe/d (90% oil)

(1) 7,708’ lateral length

Fezzik A 2443WA Fezzik A 2444WA

30 Day Avg Peak Rate:

1,536 Boe/d (89% oil)

ROCKSTAR NEW WELL RESULTS

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NEW WELLS CONTINUE OUTPERFORMANCE TREND

Note: Monthly data normalized to days on production; as of April 26, 2018 (1) Previously Reported Well Average includes all (36) previously reported SM operated wells on production since 11/3/2016. (2) New Well Average includes 19 new wells that have not been previously reported.

50,000 100,000 150,000 200,000 250,000 300,000 30 60 90 120 150 180 210 240 270 300 330 360

Cumulative Production (BOE) Days on Production Previously Reported Well Avg New Well Avg PEER 1MMBOE

(1) (2)

MIDLAND BASIN INFRASTRUCTURE WATER MANAGEMENT

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INVESTING $70MM IN FRESH AND PRODUCED WATER INFRASTRUCTURE IN 2018

Accelerates development Expected cost savings

(LOE + Capital)

System control Currently 95%+ Midland water on pipe

MIDLAND BASIN INFRASTRUCTURE REGIONAL SAND

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POSITIVE ARRANGEMENT WITH US SILICA & SANDBOX LOGISTICS

Lamesa (3Q18) Crane (1Q18)

~55 miles(1) ~48 miles(1)

New sand mines close to SM

• perations

>$400K

expected capital savings per well

(1) Road miles

MIDLAND BASIN INFRASTRUCTURE TAKEAWAY

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MULTIPLE PURCHASERS WITH FT ASSURE RELIABLE SM TAKEAWAY

Multiple purchasers with FT; excellent relationships Sales at wellhead; gathering is firm ~90% of oil on pipe High quality WTI used by TX refineries; SM oil 37-41 gravity

Permian Basin Oil Takeaway

• Up-spacing to improve returns
• Assessing new intervals
• Optimizing completions
• Running 2 rigs and 1 frac fleet
• Expect to complete 9 net wells

in 2Q18

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EAGLE FORD

ENHANCING VALUE OF INVENTORY Eagle Ford

~165,000 net acres

JV Area

BALANCE SHEET OFFERS FINANCIAL FLEXIBILITY

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LIQUIDITY OF $1.6B, INCLUDING $643MM CASH ON HAND(1)

$500 $500 $500 $395 $562 $345

$172.5

$0 $250 $500 $750 $1,000 $1,250 $1,500 2026 2025 2024 2023 2022 2021 2020 2019 2018

Debt Maturities(1)

(in millions)

$0 drawn Borrowing Base: $1.27B(2) Commitments: $1.0B(2)

Coupon

1.500% 6.500% 6.125% 6.500% 5.000% 5.625% 6.750%

Yield to worst(3)

5.41% 5.41% 5.79% 6.26% 6.48% 6.63%

Initial call date

11/2016 11/2018 7/2017 7/2018 6/2020 9/2021

Initial call price

103.25% 103.06% 103.25% 102.50% 102.81% 103.38%

(1) As of March 31, 2018; borrowing base and commitment amount as of May 30, 2018 (2) Borrowing base updated for Divide County asset sale; commitments unchanged (3) As of May 29, 2018

• Rapidly reducing net debt with $792MM non-core asset sales year-to-date
• Net debt:TTM Adjusted EBITDAX 3.3 times at 3/31/18; below 3.0 times projected year-end
• No bond maturities until 2021
• Senior Secured Debt:TTM Adjusted EBITDAX at 0.0 times; max ratio allowed 2.75 times
• TTM Adjusted EBITDAX:Interest at ~4.1 times; minimum ratio required 2.0 times

WELL HEDGED

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PERCENTAGE OF EXPECTED PRODUCTION HEDGED

Production Hedged(1)

80% 70%

Midland-Cushing Basis Swaps

• ~80% of expected 2Q18 – 4Q18 production volumes

hedged; ~85% of oil volumes, ~65% of gas volumes (NGLs hedged by product)

• ~75% of expected 2Q18 production volumes hedged;

~75% of oil volumes, ~65% of gas volumes (NGLs hedged by product)

• ~40% of expected 2019 production volumes hedged;

~50% oil volumes, ~25% gas volumes (NGLs hedged by product)

• ~70% of expected 2Q18 – 4Q18 Permian oil

production covered by basis hedges at just over $1/Bbl

• ~45% of expected 2019 Permian oil production

covered by basis hedges

Note: Hedging data as of May 18, 2018; all percentages calculated using mid-point of guidance.

(1) Percentage includes oil swaps and collars, natural gas swaps and collars, and NGL swaps; does not include basis swaps.

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SM ENERGY WHY INVEST IN SM?

OBJECTIVE; DELIVER LONG-TERM GROWTH IN CASH FLOW PER DEBT ADJUSTED SHARE

25-well cube development; Pads from left to right: Ensign 772, Ensign 769, Trinidad 57, and Ensign 767

• Unique opportunity to participate in competitively high rate of change in oil

production, margin expansion and cash flow growth

• Assets: SM wells ranked best in Midland Basin
• Execution: Exceptional track record; growing inventory
• Rapidly strengthening balance sheet with ample liquidity
• Returns focused: executive compensation tied to returns

Appendix

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Operational Detail

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Benchmark Pricing NYMEX WTI Oil ($/Bbl) $62.87 NYMEX Henry Hub Gas ($/MMBtu) $3.00 Hart Composite NGL ($/Bbl) $30.87 Production Volumes Eagle Ford(1) Permian Rocky Mountain Total Oil (MBbls) 354 3,315 592 4,262 Gas (MMcf) 18,731 5,631 861 25,222 NGL (MBbls) 1,641 5 27 1,673 MBoe 5,117 4,259 763 10,139 Revenue (in thousands) Oil $19,583 $205,794 $35,683 $261,060 Gas 52,733 24,876 1,500 79,109 NGL 41,770 124 823 42,717 Total $114,086 $230,794 $38,006 $382,886 Expenses (in thousands) LOE $11,321 $28,292 $10,572 $50,174 Ad Valorem 2,361 4,366 50 6,777 Transportation 45,307 197 1,396 46,900 Production Taxes 1,921 11,359 3,748 17,028 Per Unit Metrics: Realized Oil per Bbl $55.27 $62.07 $60.27 $61.25 % of Benchmark - WTI 88% 99% 96% 97% Realized Gas per Mcf $2.82 $4.42 $1.74 $3.14 % of Benchmark – NYMEX HH 94% 147% 58% 105% Realized NGL per Bbl $25.45 $24.29 $30.36 $25.53 % of Benchmark – HART 82% 79% 98% 83% Realized per Boe $22.29 $54.19 $49.84 $37.76 LOE per Boe $2.21 $6.64 $13.86 $4.95 Transportation per Boe $8.85 $0.05 $1.83 $4.63 Ad Val per Boe $0.46 $1.03 $0.07 $0.67 Production Tax - per BOE/% of Pre-Hedge Revenue $0.38/1.7% $2.67/4.9% $4.92/9.9% $1.68/4.4% Production Margin per Boe $10.39 $43.80 $29.16 $25.83

Note: Totals may not sum due to rounding and other classifications (1) Includes nominal amounts of other production and expenses from the region.

1Q18 REALIZATIONS BY REGION

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2018 PLANNED RIG ACTIVITY AND COMPLETIONS BY MONTH

20 40 60 80 100 120 2 4 6 8 10 12 14 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Total Net DUCs(1) Operated Rigs Midland Basin Eagle Ford Total Net DUCs

(1) Total Net DUCs counts remove DUCs associated with assets sold.

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NGL REALIZATIONS

• 16% increase in realized price (before hedges) from 1Q17 to 1Q18
• SM NGL price realizations are predominantly tied to Mont Belvieu, fee

based contracts

• Differential reflects NGL barrel product mix, and transportation and

fractionation fees

42% 27% 9% 9% 13%

SM Typical NGL Bbl(1)

Ethane Propane Iso Butane Normal Butane Natural Gasoline

1Q17 2Q17 3Q17 4Q17 1Q18

• Mt. Belvieu ($/Bbl)

$26.74 $24.11 $27.55 $32.12 $30.87

SM Realization ($/Bbl)

$22.06 $19.71 $22.40 $26.01 $25.53

% Differential to

• Mt. Belvieu

82% 82% 81% 81% 83%

(1) Includes the effects of ethane rejection

2018 ACTIVITY BY REGION

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WELLS DRILLED, FLOWING COMPLETIONS, AND DUC COUNT

Wells Drilled Flowing Completions DUC Count

1st Quarter 2018 1st Quarter 2018 1st Quarter 2018

Region

Gross Net Gross Net Gross Net

Permian Sweetie Peck

3 3 4 2 8 8

RockStar

32 30 18 15 54 50

Permian total

35 33 22 17 62 58

Eagle Ford(1)

11 8 5 5 39 33

Rocky Mountain (Divide)

• 18

15

Subtotal Operated Wells

46 41 27 22 119 106

Non-operated Wells(3)

n/a

• n/a
• n/a

1

Total

n/a 41 n/a 22 n/a 107

(1) As of March 31, 2018, there were 4 gross JV wells drilled, 0 JV wells completed, and 8 gross JV DUC’s (2) Expected to be sold during 2Q18 (3) Non-operated activity relates to wells located in the Permian Basin

(2)

LEASEHOLD SUMMARY

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PRO-FORMA FOR PENDING TRANSACTIONS

Region

Net Acres(1) 3/31/18 2Q Sales / Additions Pro-forma Net Acres Midland Basin RockStar 64,855 760 65,615 Sweetie Peck(2) 16,900

• 16,900

Halff East 5,420 (5,420)

• Midland Basin Total

87,175 (4,660) 82,515 Eagle Ford 164,680

• 164,680

Rocky Mountain Divide 119,235 (119,235)

• Rocky Mountain Other(3)

186,845

• 186,845

Other Areas/Exploration 24,915

• 24,915

Total 582,850 (123,895) 458,955

(1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of March 31, 2018. (2) Sweetie Peck acreage includes 2,450 net acres of drill-to-earn acreage. (3) Rocky Mountain Other includes non-core Williston Basin, and other non-core acreage located in North Dakota, Montana, Wyoming, and Utah.

Financial Detail

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OIL AND GAS DERIVATIVE POSITIONS

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BY QUARTER THROUGH 2019

Midland - Cushing Oil Swaps Oil Collars Oil Basis Swaps

Period Volume (MBbls) $/Bbl(1) Volume (MBbls) Ceiling $/Bbl(1) Floor $/Bbl(1) Volume (MBbls)

Price Differential $/Bbl(1) 2Q’18 1,534 $49.57 1,459 $59.03 $50.00 2,392 ($1.03) 3Q’18 1,769 $49.77 1,948 $58.61 $50.00 3,018 ($1.06) 4Q’18 1,894 $49.87 2,222 $58.44 $50.00 3,327 ($1.08) 1Q’19 442 $50.70 1,865 $61.08 $49.38 1,471 ($1.27) 2Q’19 439 $50.70 1,990 $61.44 $49.66 1,546 ($1.32) 3Q’19 524 $50.70 2,079 $61.51 $48.26 3,113 ($2.75) 4Q’19 535 $50.70 2,092 $61.46 $48.25 3,132 ($2.74)

Note: Includes all commodity derivative contracts for settlement at any time during the second quarter of 2018 and later periods through 2019, entered into as of 5/18/18. (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.

Gas Swaps Gas Collars

Period Volume (BBTU) $/MMBTU(1)

Volume (BBTU) Ceiling $/MMBTU(1) Floor $/MMBTU(1) 2Q’18 15,712 $2.85

• 3Q’18

17,147 $2.88

• 4Q’18

18,646 $2.91

• 1Q’19

16,979 $2.92

• 2Q’19
• 4,358

$2.83 $2.50 3Q’19

• 5,066

$2.83 $2.50 4Q’19

• 4,818

$2.83 $2.50

NGL DERIVATIVE SWAP POSITIONS

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OPIS MT. BELVIEU

Ethane Purity

Period Volume (MBbls) $/Bbl(2)

2Q’18 915 $10.87 3Q’18 1,033 $10.99 4Q’18 1,146 $11.18 2018 Total 3,094 1Q’19 853 $12.25 2Q’19 877 $12.29 3Q’19 907 $12.34 4Q’19 896 $12.36 2019 Total 3,533 1Q’20 275 $11.13 2Q’20 264 $11.13 2020 Total 539

Propane

Period Volume (MBbls) $/Bbl(2)

2Q’18 554 $24.94 3Q’18 610 $24.27 4Q’18 671 $24.39 2018 Total 1,835 1Q’19 440 $26.13 2Q’19 348 $28.53 3Q’19 360 $28.53 4Q’19 355 $28.53 2019 Total 1,503

Iso Butane

Period Volume (MBbls) $/Bbl(2)

2Q’18 66 $35.07 3Q’18 70 $35.07 4Q’18 76 $35.07 2018 Total 212 1Q’19 29 $35.70 2Q’19 29 $35.70 3Q’19 30 $35.70 4Q’19 29 $35.70 2019 Total 117

Natural Gasoline

Period Volume (MBbls) $/Bbl(2)

2Q’18 175 $50.99 3Q’18 202 $51.13 4Q’18 208 $50.99 2018 Total 585 1Q’19 48 $50.93 2Q’19 49 $50.93 3Q’19 50 $50.93 4Q’19 50 $50.93 2019 Total 197

Normal Butane

Period Volume (MBbls) $/Bbl(2)

2Q’18 84 $35.69 3Q’18 93 $35.70 4Q’18 102 $35.70 2018 Total 279 1Q’19 37 $35.64 2Q’19 38 $35.64 3Q’19 39 $35.64 4Q’19 39 $35.64 2019 Total 153 (1) Includes all commodity derivative contracts for settlement at any time during the second quarter of 2018 and later periods, entered into as of May 18, 2018. (2) Weighted-Average Contract Price

1ST QUARTER 2018

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SOLID EXECUTION

Production & Pricing 1Q18

Total Production (MMBoe/MBoe/d) 10.1/112.7 Oil Percentage 42% Pre-Hedge Realized Price ($/Boe) $37.76 Post-Hedge Realized Price ($/Boe) $35.34

Costs $/Boe

LOE $4.95 Ad Valorem $0.67 Transportation $4.63 Production Taxes $1.68 Production Expenses $11.93 Cash Production Margin (pre-hedge) $25.83 G&A – Cash $2.33 G&A – Non Cash $0.40 Operating Margin (pre-hedge) $23.10 DD&A $12.87

$210.2 MM

Adjusted EBITDAX(1)

(1) See Appendix for reconciliation of non-GAAP measures

$168.7 MM

Discretionary Cash Flow (1)

30% increase

(over 4Q17)

TOTAL CAPITAL SPEND

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RECONCILIATION TO COSTS INCURRED (GAAP)

Reconciliation of costs incurred in oil and gas activities (GAAP) to total capital spend (Non-GAAP)(1) (in millions) Three Months Ended March 31, 2018

Costs incurred in oil and gas activities (GAAP):

$372.2

Asset retirement obligation

(0.9)

Capitalized interest

(4.5)

Total capital spend (Non-GAAP):

$366.7

(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. Note: Amounts may not calculate due to rounding

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ADJUSTED EBITDAX RECONCILIATION

Reconciliation of net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP): (in thousands) Three Months Ended March 31, 2018

Net income (GAAP) $317,401 Interest expense 43,085 Interest income (849) Income tax expense 98,991 Depletion, depreciation, amortization, and asset retirement obligation liability accretion 130,473 Exploration(1) 12,411 Abandonment and impairment of unproved properties 5,625 Stock-based compensation expense 5,412 Net derivative loss 7,529 Derivative settlement loss (24,528) Net gain on divestiture activity (385,369) Other 7 Adjusted EBITDAX (Non-GAAP) $210,188 Interest expense (43,085) Interest income 849 Income tax expense (98,991) Exploration(1) (12,411) Amortization of debt discount and deferred financing costs 3,866 Deferred income taxes 98,366 Other, net (2,534) Changes in current assets and liabilities (16,113) Net cash provided by operating activities (GAAP) $140,135

Adjusted EBITDAX represents 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 we believe 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 we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our 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

• f 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 other 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. Our credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed 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, we would be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.

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

31

ADJUSTED NET INCOME RECONCILIATION

Reconciliation of net income (GAAP) to adjusted net income (non-GAAP): (in thousands, except per share data) Three Months Ended March 31, 2018

Net income (GAAP) $317,401 Net derivative loss 7,529 Derivative settlement loss (24,528) Net gain on divestiture activity (385,369) Abandonment and impairment of unproved properties 5,625 Other, net 807 Tax effect of adjustments(1) 86,710 Adjusted net income (Non-GAAP) $8,175 Diluted net income per common share (GAAP) $2.81 Net derivative loss 0.07 Derivative settlement loss (0.22) Net gain on divestiture activity (3.41) Abandonment and impairment of unproved properties 0.05 Other, net 0.01 Tax effect of adjustments(1) 0.76 Adjusted net income per diluted common share (Non-GAAP) $0.07 Diluted weighted-average common shares outstanding (GAAP): 112,879

Adjusted net income 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, impairments, net (gain) loss on divestiture activity, materials inventory loss, and gains or losses on extinguishment of debt. The non-GAAP measure of adjusted net income (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 income (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 income (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 income (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) The tax effect of adjustments is calculated using a tax rate of 21.9%, for the three-month period ended March 31, 2018. This rate approximates the Company's statutory tax rate adjusted for ordinary permanent differences. Note: Amounts may not calculate due to rounding

DISCRETIONARY CASH FLOW

32

RECONCILIATION TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

Reconciliation of net cash provided by operating activities (GAAP) to discretionary cash flow (Non-GAAP)(1) (in millions) Three Months Ended March 31, 2018

Net cash provided by operating activities (GAAP):

$140.1

Changes in current assets and liabilities

16.1

Exploration(2)(3)

12.4

Discretionary cash flow (Non-GAAP):

$168.7

(1) Discretionary cash flow is defined as net cash provided by operating activities excluding changes in assets and liabilities, and exploration (included in

• ur capital spend guidance). Discretionary cash flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash

which is used to internally fund exploration and development activities, pay dividends, and service debt. Discretionary cash flow is presented because management believes it provides useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities, or have different financing and capital structures or tax rates. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income. (2) Exploration expense is added back in the calculation of discretionary cash flow because for peer comparison purposes, this number is included in our reported total capital spend. (3) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the statements of operations for the component of stock-based compensation expense recorded to exploration expense. Note: Amounts may not calculate due to rounding

Inventory and Returns

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HOWARD COUNTY WOLFCAMP A

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EVOLUTION OF SM SWEET SPOT MAPPING January 2017 February 2018

Hyden 47-38 WA 1H Grenadier – 9,639’ 24hrIP = 848 BOEPD Higginbotham Unit B 30-19 1AH Tall City – 6,397’ 24hrIP = 398 BOEPD Cassidy 26-23 1H Tall City – 7,314’ 24hrIP = 403 BOEPD Viper 14-9 1WA SM – 10,422’ 24hrIP = 1,316 BOEPD Oldham Trust 40-25 WA 1H Grenadier – 10,426’ 24hrIP = 1,274 BOEPD Thumper 14-23 1AH Sabalo – 10,105’ 24hrIP = 1,357 BOEPD Midland 15-10 1WA Hannathon – 7,726’ 24hrIP = 1,259 BOEPD Broughton Wise 18-19 WA 1H Grenadier – 7,012’ 24hrIP = 875 BOEPD Morgan Ranch 38-47 1WA Hannathon – 7,727’ 24hrIP = 713 BOEPD

HOWARD COUNTY WOLFCAMP B

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EVOLUTION OF SM SWEET SPOT MAPPING January 2017 February 2018

International Unit 9H Callon – 7,579’ 24hrIP = 887 BOEPD Maverick 0361WB SM – 10,412’ 24hrIP = 1,683 BOEPD Sundown 4566WB SM – 10,336’ 24hrIP = 1,435 BOEPD Prichard J 10BH Legacy – 7,644’ 24hrIP = 602 BOEPD Prichard J 9BH Legacy – 7,641’ 24hrIP = 655 BOEPD Fletch C 1368WB SM – 10,287’ 24hrIP = 1,700 BOEPD Tubb 1WA Crownquest – 9,873’ 24hrIP = 1,178 BOEPD

HOWARD COUNTY LOWER SPRABERRY

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EVOLUTION OF SM SWEET SPOT MAPPING January 2017 February 2018

Moby Dick 31-30 8SH Surge – 7,362’ 24hrIP = 319 BOEPD Sundown 4524 LS SM – 10,352’ 24hrIP = 959 BOEPD

• Mr. Phillips 11-2 1SH

Sabalo – 10,047’ 24hrIP = 1,032 BOEPD Papagiorgio 33-40 B1LS SM – 10,370’ 24hrIP = 1,006 BOEPD Allar LS Hannathon – 7,580’ 24hrIP = 1,135 BOEPD

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

Drilling Locations (gross operated)

Economic Resource Additional Resource

MIDLAND BASIN DRILLING INVENTORY

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INCREASING INVENTORY AND NPV PER SECTION

~1,250

Average Lateral Length

9,600’

(up 13% from 2016) Average Working Interest

72%

(up 10% from 2016) Economic lateral feet increased

17%

(from 2016) 10% IRR threshold economic locations:

1,640

(2)

(comparable to peers)

(1) Economic Resource represents 3P inventory within the confirmed contours and 20% IRR at $60/Bbl oil, $3/MMBtu natural gas, $30/Bbl NGLs (2) 3P inventory inside and outside the confirmed contours; 10% IRR

(1)

DRILLING INVENTORY ~15 YEARS AT CURRENT ACTIVITY LEVEL

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APPROXIMATELY 45 YEARS INCLUDING UPSIDE RESOURCES Midland Basin and Eagle Ford

1,000 2,000 3,000 4,000 5,000 6,000

Drilling Locations (gross operated)

Economic Resource Additional Resource

Note: Eagle Ford 2017 average lateral length = 9,000’; up 18% from 2016

(1) Economic Resource represents 3P inventory within the confirmed contours for Howard and Martin Counties and 20% IRR at $60/Bbl oil, $3/MMBtu natural gas, $30/Bbl NGLs

(1)

0% 10% 20% 30% 40% 50% 60% $0.60 $0.70 $0.80

IRR

• Mt. Belvieu $/Gal

0% 20% 40% 60% 80% 100% $50 $55 $60 $65

IRR NYMEX WTI

TOP TIER ASSETS REGIONAL WELL PROJECTED ECONOMICS

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0% 20% 40% 60% 80% 100% 120% $50 $55 $60 $65

IRR NYMEX WTI

RockStar

Wells(1) across all intervals (WCA, WCB, LS) in the 2018 drilling program

Well Cost: $8.3MM Well Spacing: 513’ – 660’

Sand loading: 1,900 lbs/ft; Stage Spacing: 167’; Length: 10,000’

Sweetie Peck

Wells(1) across all intervals (WCA, WCB, LS) in the 2018 drilling program

Well Cost: $7.5MM Well Spacing: 660’

Sand loading: 1,900 lbs/ft; Stage Spacing: 167’; Length: 8,333’

Eagle Ford

Wells(1) across UEF/LEF in East, South and North Area in the 2018 drilling program

Well Cost: $6.8MM, Lateral Length: 8,800’, Well Spacing: 625’-900’, Sand Loading: 2,000 lbs/ft, Stage Spacing: 150’

1Q18 Average

• Mt. Belvieu ($/Gal)

Note: well costs include drill, complete, and equip; sensitivities at $3.00/MMBtu NYMEX; Eagle Ford oil flat at $60/Bbl WTI, excludes JV wells (1) Weighted average by interval

Maps

40

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ROCKSTAR OPERATORS

SM Energy Callon Encana Surge/Yantai Xinchao Diamondback Oxy Energen Endeavor Sabalo Grenadier

Note: Peer acreage obtained from 1Derrick

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SWEETIE PECK OPERATORS

SM Energy Apache Chevron Concho Devon Diamondback Discovery Endeavor Exxon Legacy Oxy Pioneer Summit

Note: Peer acreage obtained from 1Derrick

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EAGLE FORD OPERATORS

Fasken Area North Area East Area South

Dimmit Webb Dimmit Maverick

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DEFINITIONS OF NON-GAAP, FORWARD LOOKING METRICS

The following metrics are forward-looking non-GAAP financial measures. The Company believes these measures are commonly used in the E&P industry, and other industries, by shareholders, professional research analysts and others in valuation, comparison and investment recommendations. Certain forward-looking metrics cannot be presented in conjunction with a reconciliation to the closest GAAP measure, because certain portions of the forecast calculation would are inherently

• unpredictable. Accordingly, investors are cautioned not to place undue reliance on these numbers.

1) Projected cash flow per debt adjusted share: For purposes of forward-looking cash flow from operations, it is not possible to project changes in working capital. The Company calculates forward-looking cash flow as projected adjusted EBITDAX (reconciled above to GAAP Net Loss and GAAP Net cash provided by operating activities for actual results) less projected cash interest expense and cash taxes. The calculation of debt adjusted shares is the sum of average fully diluted common shares outstanding plus the quotient of total principal value

• f long-term debt outstanding (including senior notes, convertible stock, credit facility) less cash and cash equivalents divided by the price of

common stock. In the case of the current 2-year plan, the price of common stock used is the closing price at year-end 2017. 2) Capital spend: For purposes of forward-looking capital spend, it is the sum of projected capital expenditures for drilling and completion of wells, capitalized geologic and geophysical work, exploration costs excluding dry hole expenses, facilities and infrastructure, allocated overhead and land costs exclusive of acquisitions. Capital spend as reported for actual results is reconciled above to GAAP costs incurred in oil and gas activities. 3) Net debt:EBITDAX: Net debt is total principle value of long-term debt outstanding less cash and cash equivalents. Projected net debt:EBITDAX is projected net debt divided by projected adjusted EBITDAX. Adjusted EBITDAX is reconciled above to GAAP Net Loss and GAAP Net cash provided by operating activities for actual results. 4) Discretionary cash flow Discretionary cash flow is defined as net cash provided by operating activities excluding changes in assets and liabilities, and exploration (included in our capital spend guidance).

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CONTACT INFORMATION

Jennifer Martin Samuels Vice President - Investor Relations 303-864-2507 jsamuels@sm-energy.com