2017 Results and 2018 Operating Plan FEBRUARY 21, 2018 PREMIER OPERATOR OF TOP TIER ASSETS

Transcription

1 2017 Results and 2018 Operating Plan FEBRUARY 21, 2018 PREMIER OPERATOR OF TOP TIER ASSETS 1

2 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 forwardlooking statements. Forward-looking statements in this presentation include, among other things, full year 2018 guidance, first quarter of 2018 guidance, expectations concerning the planned closing of a previously announced divestiture, expectations about future cost inflation, and the expected benefits from joint venture arrangements. General risk factors include 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 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 (including any delay in closing our announced PRB divestiture as a result of litigation); 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 of 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 Reserves and resources: See Appendix for disclosure statement Non-GAAP forward looking metrics: See Appendix for definitions 2

3 Driving Differential Value Measuring returns: 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) Premier Operator + = Top Tier assets ~35% Cash Flow Growth per Debt Adjusted Share (1) (1) See Appendix for Cash Flow per Debt Adjusted Share definition (2) William Featherston/Betty Jiang, Credit Suisse 3

4 Premier Operator of Top Tier Assets 2017 marked by outstanding execution Top operator SM ranks #1 in the Midland Basin on a revenues per lateral foot basis - Baird (1) Key differentiator is Howard County acreage - Deutsche Bank (2) Midland Basin production growth (3) 165% Increased average lateral feet per well (4) ~1,200 Raised cash operating margin (3) 48% Increased proved reserves (5) 47% Increased PV-10 (6) 2.5x (1) Baird 12/18/17 Joseph Allman (4) 2017 average lateral feet compared to acquisition assumptions (2) Deutsche Bank 2/1/18 Nitin Kumar (5) 2017/2016; retained assets (3) 4Q17/4Q16 (6) See Appendix for reconciliation of PV-10 (Non-GAAP) to Standardized Measure (GAAP) 4

5 Plan Overview & Guidance 5

6 Cash Flow per Net Debt Adjusted Share Net Debt : TTM EBITDAX Plan Highlights Big cash flow growth per debt adjusted share near 35% projected CAGR Expected to nearly double cash flow per debt adjusted share in two years Expected to cut Net Debt : TTM EBITDAX by approximately 1.5 turns $ $ $ e 2019e Cash Flow per Net Debt Adjusted Share Net Debt : TTM EBITDAX (1) 0 (1) See Appendix for Cash Flow per Debt Adjusted Share definition (2) Net Debt : TTM EBITDAX: see Appendix for definition. 6

7 Production (MBoe) Cash Operating Margin $/Boe Plan Highlights Big Midland production growth driving expected margin expansion Midland projected production growth up ~135% Company projected cash operating margin up over 45% ,000 $22 50,000 40,000 30,000 $16 20,000 10, e 2019e Midland Basin Eagle Ford Rockies Sold/Pending Sale Operating Margin $10 (1) (1) Realized price before the effect of hedges (2018e: current strip pricing through 1Q18 and $55/$3 for remainder of 2018; price normalized for 2019e) less LOE, ad valorem, transportation, production taxes, and cash G&A. 7

8 SM Energy A Premier Operator of Top Tier Assets Objective: to deliver long-term growth in cash flow per debt adjusted share 2 Year Plan Expected Outcomes: Big growth in high-margin production Cash flow neutrality by MY 2019 Net Debt:EBITDAX ~2.5x YE Priorities: Operational excellence / capital efficiency Reduce debt / continue to core up portfolio Focused capital program to drive margin expansion 8

9 2018 Capital Program Aggressive growth expected in the Midland Basin Total Capital Spend ~$1.27B D&C Budget ~$1.04B Drilling and Completion 82% Facilities 10% Other (1) 8% Midland Basin 86% Eagle Ford 14% Currently running 9 rigs in Midland Basin; expected to decline to 7 rigs by year-end (expected average of 8 for full year); expected average 1 rig in Eagle Ford for full year Planning ~150 net wells drilled (2) and ~125 net completions (3) D&C budget assumes 10-15% cost inflation per lateral foot versus 2017 average Facilities expenditures include buildout of Midland water handling system for ~$70MM (1) Other includes exploration, allocated overhead, and land. (3) Expect to complete ~100 net wells in Midland and ~25 net (2) Expect to drill ~130 net wells in Midland and ~17 net wells in Eagle Ford wells in Eagle Ford 9

10 Production (Boe/d) 2018 Plan Guidance (1) Capital & Production FY 2018 Total Capital Spend ($MM) (2) (before acquisitions) ~$1,270 Total Production (MMBoe) Oil % ~41% Costs LOE ($/Boe) ~$ Production Guidance by Quarter Ad Valorem taxes ($/Boe) Operated Eagle $ $0.65 Transportation ($/Boe) Ford 20% ~$4.50 Production taxes ($/Boe) ~$1.55 G&A ($MM) includes ~$20MM non-cash compensation Capitalized Overhead/Exploration ($MM) before dry hole expense, all of which is included in capital expenditure guidance $ $70-75 DD&A ($/Boe) $ $ % 1Q18e 2Q18e 3Q18e 4Q18e 86% 8% Retained Assets Pending Sale > 1Q18 production guidance 9.5 to 10.0 MMBoe > LOE expected to exceed the average in 1H18 and be below the average in 2H18 as Permian costs are reduced with completion of water handling systems > Transportation expense expected to decline sequentially through the year as higher cost Eagle Ford production is a reduced proportion of the commodity mix (1) As of February 21, 2018 (2) Total Capital Spend is a non-gaap financial measure. Please see the reconciliation of this measure in the Appendix. 10

11 2017 Reserves at Year-End 11

12 2017 Proved Reserves Additions and Revisions Proved reserves of retained assets up 47% Net proved reserve additions of 192MM Boe equaled 4.3 times production More than doubled proved reserve PV-10 to $3.1B (1) Proved Reserves (MMBoe) YE16 Proved Reserves Production Divestitures Acquisitions Adds/ Infills 46% Proved Developed Aged PUD's 192 MMBoe Price Revision Performance Revision YE17 Proved Reserves 34% Oil, 46% Natural Gas, 20% NGLs Note: Calculated in accordance with SEC Pricing at $51.34 per barrel of oil NYMEX, $3.00 per MMBtu of natural gas at Henry Hub and $27.69 per barrel of natural gas liquids ( NGLs ) at Mt. Belvieu. (1) See Appendix for reconciliation of PV-10 (Non-GAAP) to Standardized Measure (GAAP) 12

13 2017 Proved Reserves By Region Coring up the portfolio to top tier assets YE 2016 (1) (MMBoe) YE 2017 Eagle Ford Permian Rocky Mountain Total Oil (MMBbl) Gas (Bcf) ,280.1 NGL (MMBbl) Total (MMBoe) % Proved Developed 52% 34% 53% 46% Reserve growth 20% 202% (9%) 47% Permian proved reserves tripled to 160 MMBoe Note: Proved reserves at year-end 2017 include approximately 4.2 MMBoe associated with the pending sale of certain Powder River Basin assets. (1) Adjusted to show retained assets only 13

14 2018 Operations Plan 14

15 Eagle Ford 2018 Plan Objectives Value creation through better wells, longer laterals, and optimum number of wells per section Employ new technology and optimized spacing to drive improved well performance and cost savings Expect to drill ~17 net wells > 2 rigs in 1Q18 to 1 in 2Q18 > Average lateral length increased to 9,300 (from 6,500 in 2017) Expect to complete ~25 net wells, optimize completions > Average 1 completion crew > Increase fracture injection points by decreasing cluster spacing from 50 feet to 25 feet JV expected to drill and complete 16 North Area wells testing new technology, improve capital efficiency in the area, and increase asset value Test new intervals, including Austin Chalk Mexico Eagle Ford ~165,000 net acres North Area South Area Dimmit County Webb County East Area 15

16 Midland Basin 2018 Plan Objectives Value creation through better wells, longer laterals, and increasing wells per section Midland Basin ~88,000 net acres Initiate development stage in western RockStar, continue delineation in central Howard County RockStar Expect to drill ~130 net wells, optimize landing zones > 9 rigs in 1Q18 to 7 rigs at year-end (average 8 for full year) > 2 6 wells per pad Expect to complete ~100 net wells, optimize completions > Average 4 completion crews for full year Sweetie Peck Halff East 16

17 Top Midland Basin Operator SM Energy Ranks #1 in revenue per well and revenue per lateral foot (1) Baird Equity Research 1/18/18 Joseph Allman 17

18 Drilling Cost Per Lateral Foot ($/ft) Average Lateral Length (ft) Completion Cost Per Lateral Foot ($/ft) Proppant Per Lateral Foot (lb/ft) Premier Operator Permian Top tier capital efficiency Drilling Costs Completion Costs ,000 1,200 3, ,500 9,000 7,500 1, ,500 2, , , ,500 3, , , Longer, faster and cheaper! > Lateral lengths up 62% since 2014 > Lateral Feet/Day up 171% since 2014 > $/Lateral Foot down 67% since 2014 Bigger, better and faster! > Stages per day up 71% since 2014 > Fluid per lateral foot up 55% since 2014 > Sand per lateral foot up 24% since 2014 > Reduced stage spacing (200 to 167 ft/stage) 18

19 Midland Basin Infrastructure Regional Sand Deal Best in basin arrangement with US Silica and Sandbox Logistics New sand mines close to SM locations ~55 miles (1) >$400K expected capital savings per well ~48 miles (1) Lamesa (3Q18) Crane (1Q18) (1) Road miles 19

20 Midland Basin Infrastructure Water Management Invest $70MM in fresh and produced water infrastructure Accelerates development Expected cost savings (LOE + Capital) System control 20

21 New Well Results 21

22 New Well Results Howard County Great results in multiple intervals across acreage position Sundown 4566WB Sundown 4524LS Iceman 2-10A 1LS Iceman 2-10A 2LS Iceman 2-10A 3LS Papagiorgio B 1LS Jester 2131LS Maverick 0341WA Maverick 0361WB Maverick 0342WA Maverick 0321LS Maverick 0322LS Fletch C 1352WA Fletch C 1368WB Fletch B 1351WA Fletch A 1350WA 22

23 Howard County New Well Results Well Name Interval Lateral Length Peak IP Rate (BOE/d) IP Days IP per 1, Hour Peak IP Rate Stages Clusters per Stage Proppant (lbs./ft) Oil % Maverick 0341WA (1) WCA 10,418 2, day 200 2, , Maverick 0361WB (2) WCB 10,412 1, day 137 1, , Maverick 0342WA (3) WCA 10,418 1, day 192 2, , Fletch C 1352WA WCA 10,282 1, day 128 2, , Fletch C 1368WB WCB 10,287 1, day 105 1, , Fletch B 1351WA WCA 10,113 1, day 129 1, , Fletch A 1350WA WCA 9,636 1, day 150 2, , Sundown 4566WB WCB 10,336 1, day 100 1, , Lower Spraberry Iceman 2-10A 1LS LS 7, day , Iceman 2-10A 2LS LS 7, day 105 1, , Iceman 2-10A 3LS LS 7, day , Papagiorgio B 1LS LS 10, day 75 1, , Jester 2131LS (4) LS 10, day 91 1, , Maverick 0321LS (5) LS 10,419 1, day 101 1, , Maverick 0322LS (6) LS 10, day 91 1, , Sundown 4524LS LS 10, day , (1) Name changed from Maverick A 1WA (4) Name changed from Jester B 1LS (2) Name changed from Maverick A 1WB (5) Name changed from Maverick A 1LS (3) Name changed from Maverick A 2WA (6) Name changed from Maverick A 2LS 23

24 Gross Cumulative Production (BOE) Howard County Top Tier Well Performance Continues New Wolfcamp wells continue outperformance trend 300, , , , ,000 50, (1) Days on Production Previously Reported Well Avg New Well Avg PEER 1MMBOE (2) Note: Monthly data normalized to days on production. (1) Previously Reported Well Average includes all (19) previously reported SM operated wells on production since 11/3/2017. (2) New Well Avg includes new Wolfcamp A and Wolfcamp B wells that have not been previously reported. 24

25 Gross Cumulative Production (BOE) Howard County Average Production by Formation All intervals exceed peer 1 MMBoe type curve 300, , , , ,000 50, Days on Production WCA Average WCB Average LS Average PEER 1MMBOE Note: Includes SM wells completed subsequent to 10/1/16. 25

26 % of IP % of IP Differing Decline Characteristics of LS and WCA Wells % of Peak Initial Production (IP) Rates vs Time, Jester and Papagiorgio Pads 120% Jester Pad Wells 120% Papagiorgio Pad Wells 100% 100% 80% 80% 60% 60% 40% 40% 20% 20% 0% 0% DAYS DAYS JESTER WCA (BOPD/IP24HR) JESTER LS (BOPD/IP24HR) PAPAGIORGIO WCA (BOPD/IP24HR) PAPAGIORGIO LS (BOPD/IP24HR) Lower Spraberry wells reach IP peak later but decline more slowly 26

27 Inventory & Returns 27

28 Howard County Wolfcamp A Evolution of SM Sweet Spot Mapping January 2017 February 2018 Hyden WA 1H Grenadier 9,639 24hrIP = 848 BOEPD Higginbotham Unit B AH Tall City 6,397 24hrIP = 398 BOEPD Cassidy H Tall City 7,314 24hrIP = 403 BOEPD Viper WA SM 10,422 24hrIP = 1,316 BOEPD Oldham Trust WA 1H Grenadier 10,426 24hrIP = 1,274 BOEPD Thumper AH Sabalo 10,105 24hrIP = 1,357 BOEPD Midland WA Hannathon 7,726 24hrIP = 1,259 BOEPD Broughton Wise WA 1H Grenadier 7,012 24hrIP = 875 BOEPD Morgan Ranch WA Hannathon 7,727 24hrIP = 713 BOEPD 28

29 Howard County Wolfcamp B Evolution of SM Sweet Spot Mapping January 2017 February 2018 Sundown 4566WB SM 10,336 24hrIP = 1,435 BOEPD Maverick 0361WB SM 10,412 24hrIP = 1,683 BOEPD Prichard J 10BH Legacy 7,644 24hrIP = 602 BOEPD Prichard J 9BH Legacy 7,641 24hrIP = 655 BOEPD International Unit 9H Callon 7,579 24hrIP = 887 BOEPD Tubb 1WA Crownquest 9,873 24hrIP = 1,178 BOEPD Fletch C 1368WB SM 10,287 24hrIP = 1,700 BOEPD 29

30 Howard County Lower Spraberry Evolution of SM Sweet Spot Mapping January 2017 February 2018 Moby Dick SH Surge 7,362 24hrIP = 319 BOEPD Sundown 4524 LS SM 10,352 24hrIP = 959 BOEPD Mr. Phillips SH Sabalo 10,047 24hrIP = 1,032 BOEPD Papagiorgio B1LS SM 10,370 24hrIP = 1,006 BOEPD Allar LS Hannathon 7,580 24hrIP = 1,135 BOEPD 30

31 Drilling Locations (gross operated) Drilling Inventory Midland Basin Increasing inventory and NPV per section 4,000 3,500 3,000 Average Lateral Length 9,600 Average Working Interest 72% 2,500 (up 13% from 2016) (up 10% from 2016) 2,000 1,500 1,000 Economic lateral feet increased 17% 10% IRR threshold economic locations: 1,640 (2) 500 ~1,250 (from 2016) (comparable to peers) 0 (1) Economic Resource Additional Resource (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 31

32 Drilling Locations (gross operated) Drilling Inventory ~15 Years at Current Activity Level Approximately 45 years including upside resources 6,000 Midland Basin and Eagle Ford 5,000 4,000 3,000 2,000 1,000 0 Economic Resource (1) 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 32

33 IRR IRR IRR Top-Tier Assets Regional Well Projected Economics 120% RockStar Wells (1) across all intervals (WCA, WCB, LS) in the 2018 drilling program 100% Sweetie Peck Wells (1) across all intervals (WCA, WCB, LS) in the 2018 drilling program 100% 80% 80% 60% 40% 60% 40% 20% 20% 0% 0% $50 $55 $60 $65 $50 $55 $60 $65 NYMEX WTI NYMEX WTI Well Cost: $8.3MM Well Spacing: Well Cost: $7.5MM Well Spacing: 660 Sand loading: 1,900 lbs/ft; Stage Spacing: 167 ; Length: 10,000 Sand loading: 1,900 lbs/ft; Stage Spacing: 167 ; Length: 8,333 60% Eagle Ford Wells (1) across UEF/LEF in East, South and North Area in the 2018 drilling program 50% 40% 30% 20% January 2018 Average Mt. Belvieu ($/Gal) 10% 0% $0.60 $0.70 $0.80 Mt. Belvieu $/Gal Well Cost: $6.8MM, Lateral Length: 8,800, Well Spacing: , Sand Loading: 2,000 lbs/ft, Stage Spacing: 150 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 33

34 Operated Rigs Drilled But Uncompleted Wells 2018 Planned Rig Activity and Completions By Month 2018: expected ~100 net completions Midland Basin; expected ~25 net completions Eagle Ford (1) Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Midland Basin Eagle Ford Total Net DUCs 0 Note: The Company is currently operating one rig in the Powder River Basin, Wyoming, which is funded entirely through a carry arrangement with a third party 34

35 SM Energy Premier Operator of Top Tier Assets 4 recent analyst initiation reports, 4 great recommendations Value proposition SM undervalued based on CF growth per debt adjusted share - Credit Suisse 12/11/17 - William Featherston Drilling catalysts Key differentiator is its Howard County acreage that has lived up to management s expectations and belied industry and investor skepticism - Deutsche Bank 2/1/18 - Nitin Kumar Top Midland Basin operator SM ranks #1 in the Midland Basin on a revenues per lateral foot basis - Baird 12/18/17 - Joseph Allman growth asset base (Permian) sufficiently geologically derisked and SM now ideally positioned From this point forward should create a disproportionate amount of risk adjusted equity value - FBR 2/5/18 - Rehan Rashid see upside to 2018 oil production given strong Howard County well results and solid execution in 2017; less concerned about 2018 outspend given more constructive oil prices and visibility to cash flow neutrality in Credit Suisse 12/11/17 - William Featherston 35

36 Appendix 36

37 2017 Financial & Operating Results 37

38 4th Quarter and FY 2017 Performance Solid Execution Production 4Q17 FY 2017 Total Production (MMBoe) Average Daily Production (MBoe/d) Pre-Hedge Realized Price ($/Boe) $32.95 $28.20 Post-Hedge Realized Price ($/Boe) $32.16 $28.68 Costs $/Boe $/Boe LOE $5.10 $4.43 Ad Valorem $0.33 $0.34 LOE including Ad Valorem $5.43 $4.77 Transportation $5.01 $5.48 Production Taxes (~ % of pre-derivative oil, gas & NGL revenue) $1.41 $1.18 Production Expenses $11.85 $11.43 Cash Production Margin (pre-hedge) $21.10 $16.77 G&A Cash $2.69 $2.28 Cash Margin (pre-hedge) $18.41 $14.49 G&A Non Cash $0.69 $0.43 DD&A $12.69 $

39 Well Hedged (1) 2018 percentage of expected production hedged Production Hedged ~85% of expected 1Q18 production volumes hedged (2) ; ~65% of oil volumes, ~85% of gas volumes (NGLs hedged by product) % ~75% of expected 2018 production 95% volumes hedged (2) : ~75% of oil volumes, ~65% of gas volumes (NGLs hedged by product) Credit Agreement allows hedging of up to 85% of projected production for the first three years Significant hedge positions limit effect of oil price changes when price is greater than $57/Boe or less than $51/Boe Note: The hedged volumes on this slide do not include any volumes related to basis swaps. See Appendix for details. (1) Hedging data as of February 15, 2018 (2) At mid-point of guidance 39

40 Balance Sheet Solid Position Entering 2018 Liquidity of $1.2B, including $314MM cash on hand (1) Balance Sheet offers financial flexibility > 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 ~3.8 times; minimum ratio required 2.0 times Corporate ratings: S&P BB-, Moody s B1 Debt Maturities (1) (in millions) Commitments and Borrowing Base: $925 million (3) $172.5 $1,000 Facilities 6% $750(1) Other 8% 86% Other $500 86% 8% Drilling and Completion ~$0 drawn $ $ $ $ $ $ $250 $0 Coupon 1.500% 6.500% 6.125% 6.500% 5.000% 5.625% 6.750% Yield to worst (2) 5.66% 5.64% 6.38% 6.13% 6.56% 6.59% Initial call date 11/ /2018 7/2017 7/2018 6/2020 9/2021 Initial call price % % % % % % (1) As of December 31, 2017 (3) Reaffirmed November 2017 (2) As of February 15,

41 4Q17 Regional Realizations Benchmark Pricing NYMEX WTI Oil ($/Bbl) $55.40 NYMEX LLS Oil ($/Bbl) $60.98 NYMEX Henry Hub Gas ($/MMBTU) $2.93 Hart Composite NGL ($/Bbl) $32.12 Production Volumes Eagle Ford (1) Permian Rocky Mountain SM Total Oil (MBbls) 355 2, ,817 Gas (MMcf) 20,423 4, ,992 NGL (MBbls) 2, ,206 MBOE 5,922 3, ,356 Revenue (in thousands) Oil $17,012 $152,432 $34,105 $203,549 Gas 56,750 21,501 2,003 80,254 NGL 56, ,149 57,384 Total $129,855 $174,075 $37,257 $341,188 Expenses (in thousands) LOE $16,381 $25,383 $11,042 $52,807 Ad Valorem 2, ,444 Transportation 50, ,564 51,931 Production Taxes 2,421 8,637 3,592 14,650 Per Unit Metrics: Realized Oil/Bbl $47.91 $53.94 $53.58 $53.32 % of Benchmark - WTI 86% 97% 97% 96% Realized Gas/Mcf $2.78 $4.66 $2.11 $3.09 % of Benchmark NYMEX HH 95% 159% 72% 105% Realized NGL/Bbl $25.94 $26.36 $30.12 $26.01 % of Benchmark HART 81% 82% 94% 81% Realized BOE $21.93 $48.34 $44.73 $32.95 LOE/BOE $2.77 $7.05 $13.26 $5.10 Ad Val/BOE $0.42 $0.26 $0.04 $0.33 Transportation/BOE $8.48 $0.05 $1.88 $5.01 Production Tax- per BOE/% of Pre-Hedge $0.41/1.9% $2.40/5.0% $4.31/9.6% $1.41/4.3% Revenue Production Margin $9.86 $38.59 $25.24 $21.09 Note: Totals may not sum due to rounding and other classifications (1) Includes nominal amounts of other production and expenses from the region. 41

42 2017 Activity Wells Drilled, Flowing Completions & DUC Count Wells Drilled Flowing Completions DUC Count 4th Quarter YTD 4th Quarter YTD As of 12/31/17 Region Gross Net Gross Net Gross Net Gross Net Gross Net Permian Sweetie Peck RockStar Permian total Eagle Ford Rocky Mountain Divide County Powder River Basin (1) Rocky Mountain total Subtotal Operated Wells Non-operated Wells (2) n/a 1 n/a 4 n/a - n/a 3 n/a 1 Total n/a 35 n/a 123 n/a 24 n/a 111 n/a 87 As of December 31, 2017 (1) Activity in the Powder River Basin is provided by third party services and funding. (2) Non-operated activity relates to wells located in the Permian Basin. 42

43 Leasehold Summary Pro-forma for pending transactions Midland Basin Net Acres (1) 12/31/17 Pending Sales Pro-forma Net Acres RockStar 65,150-65,150 Sweetie Peck (2) 17,265-17,265 Halff East (Upton County) 5,420-5,420 Midland Basin Total 87,835-87,835 Eagle Ford 164, ,605 Rocky Mountain Divide 119, ,415 Powder River Basin 138,545 (112,125) 26,420 Rocky Mountain Other (3) 186, ,845 Other Areas/Exploration 24,915-24,915 Total 722,160 (112,125) 610,035 (1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of December 31, (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. 43

44 Adjusted EBITDAX Reconciliation Reconciliation of net loss (GAAP) to adjusted EBITDAX (non-gaap) to net cash provided by operating activities (GAAP): (in thousands) Three Months Ended December 31, 2017 Twelve Months Ended December 31, 2017 Net loss (GAAP) $(26,258) $(160,843) Interest expense 43, ,257 Interest income (1,067) (3,968) Income tax benefit (117,145) (182,970) Depletion, depreciation, amortization, and asset retirement obligation liability accretion 131, ,036 Exploration (1) 14,484 49,879 Impairment of proved properties - 3,806 Abandonment and impairment of unproved properties 12,115 12,272 Stock-based compensation expense 6,540 22,700 Net derivative loss 115,778 26,414 Derivative settlement gain (loss) (8,168) 21,234 Net (gain) loss on divestiture activity (537) 131,028 Loss on extinguishment of debt - 35 Other, net 3,200 8,820 Adjusted EBITDAX (Non-GAAP) $173,953 $664,700 Interest expense (43,618) (179,257) Interest income 1,067 3,968 Income tax benefit 117, ,970 Exploration (1) (14,484) (49,879) Exploratory dry hole expense 2,381 2,381 Amortization of debt discount and deferred financing costs 3,798 16,276 Deferred income taxes (124,608) (192,066) Plugging and abandonment (640) (2,735) Other, net 326 (581) Changes in current assets and liabilities 29,460 69,613 Net cash provided by operating activities (GAAP) $144,780 $515,390 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 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 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. 44

45 Adjusted Net Loss Reconciliation Reconciliation of net loss (GAAP) to adjusted net loss (non-gaap): (in thousands, except per share data) Three Months Ended December 31, 2017 Twelve Months Ended December 31, 2017 Net loss (GAAP) $(26,258) $(160,843) Net derivative loss 115,778 26,414 Derivative settlement gain (loss) (8,168) 21,234 Net (gain) loss on divestiture activity (537) 131,028 Impairment of proved properties - 3,806 Abandonment and impairment of unproved properties 12,115 12,272 Loss on extinguishment of debt - 35 Other, net 8,200 13,820 Tax effect of adjustments (1) (45,987) (75,308) US tax reform (63,675) (63,675) Adjusted net loss (Non-GAAP) $(8,532) $(91,217) Diluted net loss per common share (GAAP) $(0.24) $(1.44) Net derivative loss Derivative settlement gain (loss) (0.07) 0.19 Net (gain) loss on divestiture activity Impairment of proved properties Abandonment and impairment of unproved properties Loss on extinguishment of debt - - Other, net Tax effect of adjustments (1) (0.42) (0.68) US tax reform (0.57) (0.57) Adjusted net loss per diluted common share (Non-GAAP) $(0.08) $(0.82) Diluted weighted-average common shares outstanding (GAAP): 111, ,428 Adjusted net 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, 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) Income taxes are calculated using a tax rate of 36.1%, for the three and twelve-month periods ended December 31, These rates approximate the Company's statutory tax rate adjusted for ordinary permanent differences. 45

46 Total Capital Spend Reconciliation Reconciliation of costs incurred in oil and gas activities (GAAP) to Total capital spend (Non-GAAP) (1)(3) (in millions) Twelve Months Ended December 31, 2017 Costs incurred in oil and gas activities (GAAP): $1,040.0 Asset retirement obligation (12.1) Capitalized interest (12.6) Proved property acquisitions (2) (1.6) Unproved property acquisitions (78.6) Other 1.3 Total capital spend (Non-GAAP): $936.4 (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 $1.4 million of ARO associated with proved property acquisitions for the year ended December 31, (3) The Company completed several primarily non-monetary acreage trades in the Midland Basin during 2017 totaling $294.0 million of value attributed to the properties surrendered. This non-monetary consideration is not reflected in the costs incurred or capital spend amounts presented above. 46

47 PV-10 Reconciliation Reconciliation of standardized measure (GAAP) to PV-10 (Non-GAAP) (1) (in millions) As of December 31, 2017 Standardized measure of discounted future net cash flows (GAAP): $3,024.1 Add: 10 percent annual discount, net of income taxes 2,573.2 Add: future undiscounted income taxes Undiscounted future net cash flows 5,803.0 Less: 10 percent annual discount without tax effect (2,746.5) PV-10 (Non-GAAP): $3,056.5 (1) The non-gaap measure of PV-10 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 PV-10 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. PV-10 should not be considered in isolation or as a substitute for other measures prepared under GAAP. 47

48 Oil and Gas Derivative Positions By quarter through 2019 Fixed Swaps Oil Gas Collars Period Period Volume Volume (MBbls) $/Bbl (1) (BBTU) $/MMBTU (1) 1Q 18 1,075 $ ,788 $3.25 2Q 18 1,534 $ ,712 $2.85 3Q 18 1,769 $ ,147 $2.88 4Q 18 1,894 $ ,646 $2.91 1Q $ ,979 $2.92 2Q $ Q $ Q $ Volume (MBbls) Oil Ceiling $/Bbl (1) Floor $/Bbl (1) 1Q 18 1,445 $59.07 $ Q 18 1,459 $59.03 $ Q 18 1,948 $58.61 $ Q 18 2,222 $58.44 $ Q 19 1,445 $59.25 $ Q 19 1,450 $59.23 $ Q 19 1,501 $59.18 $ Q 19 1,511 $59.12 $47.58 Midland Cushing Oil Basis Swaps Period Volume (MBbls) Price Differential $/Bbl (1) 1Q 18 2,113 ($1.15) 2Q 18 2,392 ($1.03) 3Q 18 3,018 ($1.06) 4Q 18 3,327 ($1.08) 1Q 19 1,366 ($1.07) 2Q 19 1,411 ($1.08) 3Q 19 1,497 ($1.09) 4Q 19 1,515 ($1.10) Note: Includes all commodity derivative contracts for settlement at any time during the first quarter of 2018 and later periods through 2019, entered into as of 2/15/18. (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. 48

49 NGL Derivative Position Detail (1) NGL Swaps OPIS Eth Purity Mt Belv Period Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q 18 1,033 $ Q 18 1,146 $ Total 4,017 NGL Swaps OPIS Propane Mt Belv Non-TET Period Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 2,463 NGL Swaps OPIS IsoButane Mt Belv Non TET Period Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 379 1Q $ Q $ Q $ Q $ Total 3,533 1Q $ Q $ Q $ Q $ Total 1,503 1Q $ Q $ Q $ Q $ Total 117 1Q $ Q $ Total 539 NGL Swaps Natural Gasoline Mt Belv Non TET Period Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 774 NGL Swaps OPIS NButane Mt Belv Non TET Period Volume (MBbls) $/Bbl (2) 1Q $ Q $ Q $ Q $ Total 485 1Q $ Q $ Q $ Q $ Total 197 1Q $ Q $ Q $ Q $ Total 153 (1) Includes all commodity derivative contracts for settlement at any time during the first quarter of 2017 and later periods entered into as of February 15, (2) Weighted-Average Contract Price 49

50 NGL Realizations 30% increase in realized price (before hedges) from 4Q16 to 4Q17 SM NGL price realizations are predominately tied to Mont Belvieu, fee based contracts Differential reflects NGL barrel product mix and transportation and fractionation fees 4Q16 1Q17 2Q17 3Q17 4Q17 Mt. Belvieu ($/Bbl) $24.11 $26.74 $24.11 $27.55 $32.12 SM Realization ($/Bbl) % Differential to Mt. Belvieu $20.02 $22.06 $19.71 $22.40 $ % 82% 82% 81% 81% SM Typical NGL Bbl (1) 13% 9% 42% 9% 27% Ethane Propane Iso Butane Normal Butane Natural Gasoline (1) Includes the effects of ethane rejection 50

51 Howard County Operators SM Energy Callon Encana Surge/Yantai Xinchao Diamondback Oxy Energen Breitburn Sabalo Grenadier 51

52 Sweetie Peck Operators SM Energy Apache Chevron Concho Devon Diamondback Discovery Endeavor Exxon Legacy Oxy Pioneer Summit Miscellaneous 52

53 Maverick Eagle Ford Operators Dimmit Dimmit Webb Area North Fasken Area East Area South 53

54 Divide County Operators Canada RE CPEG RE HES CPEG FAC RE MRX FAC HNT CLR NP Divide Williams CPEG KKN HES CLR 54

55 Reserves and Resources Information about the terms economic resources and economic inventory The Securities and Exchange Commission ( SEC ) requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions (using the trailing 12-month average first-day-of-the-month prices), operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, the Company currently does not disclose probable or possible reserves in its SEC filings. In this presentation, proved reserves attributable to the Company at December 31, 2017, are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $51.34 per Bbl of oil, $3.00 per MMBtu of natural gas, and $27.69 per Bbl of NGLs. At least 80% of the PV-10 of the Company s estimate of its total proved reserves at December 31, 2017, was audited by Ryder Scott Company, L.P. The Company may use the terms economic resource, economic inventory, additional resource and similar phrases to describe estimates of gross drilling locations that the SEC rules may prohibit from being included in filings with the SEC. These are the Company s internal estimates of drilling locations. These quantities may not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or SEC rules. Such estimates and identified drilling locations may not have been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company s interests could differ substantially from these estimates. There is no commitment by the Company to drill all of these drilling locations. The calculation of economic resources is not necessarily calculated in accordance with SEC guidelines for proved reserves and is not reviewed by third party engineers. Economic resources presented in this presentation are calculated using benchmark pricing and projected pricing, which differs from the pricing used for proved reserves. Management believes the presentation of economic resources and economic drilling inventory are useful to investors in the valuation of SM Energy; however, the calculations may not be consistent with similar metrics provided by peers. 55

56 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 of 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 ) 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. 56

57 Contact Information Jennifer Martin Samuels Vice President - Investor Relations jsamuels@sm-energy.com 57