Enercom: The Oil and Gas Conference 22 AUGUST 15, 2017 PREMIER OPERATOR OF TOP TIER ASSETS

Transcription

1 Enercom: The Oil and Gas Conference 22 AUGUST 15, 2017 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, budget, estimate, expect, forecast, guidance, intend, plan, project, will and similar expressions are intended to identify forwardlooking 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, anticipated drilling plans and capital expenditures, and anticipated growth in cash flows. 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 forwardlooking statements, it disclaims any commitment to do so except as required by securities laws. Non-GAAP financial measures: See appendix for reconciliations 2

3 SM Energy Focused 3-Year Plan Top tier oil in Midland Basin + top tier NGLs and gas in Eagle Ford Midland Basin > ~89,000 net acres > 7 Rigs / 3 Frac Crews Eagle Ford > ~167,500 net acres > 1 Rig / 1 Frac Crew 3 3

4 SM Energy Premier Operator of Top Tier Assets Capital efficiency driving value Value proposition Well results and production continue to exceed expectations Drilling catalysts Permian and Eagle Ford results demonstrate top tier asset quality Continue to add inventory in Permian and Eagle Ford while working to enhance value in other areas 4

5 First Half of 2017 Financial Highlights Outstanding execution 2017 plan on track or better EBITDAX ahead of plan despite notably lower commodity prices CAPEX less than plan despite more lateral feet completed The balance sheet remains in good shape: $560 MM cash and total liquidity of $1.5 B (1) (1) As of June 30,

6 Production (MMBoe) 2017 Guidance (1) Significant Permian Growth in Second Half Capital & Production FY 2017 Total Capital Spend ($MM) (2) (before acquisitions) ~$875 Total Production (MMBoe) oil percent in commodity mix approaches 30% average Costs LOE, including Ad Valorem ($/Boe) $ Transportation ($/Boe) Operated Eagle $ Production taxes (% of pre-hedge revenue) Ford % 20% $ G&A ($MM) incl. $20 MM non-cash compensation Capitalized Overhead/Exploration ($MM) before dry hole expense, all of which is included in capital expenditure guidance $65-70 DD&A ($/Boe) $ $ Production Guidance 6% increase Original Guidance (includes Divide County for full year) 1Q17 Revision (predominantly outperformance) Note: Midpoint of production guidance shown. Facilities 6% (1) 2Q17 Eagle Ford Acceleration 2Q17 Outperformance Raising full year production guidance by 0.8 MMBoe (midpoint) Pace of Permian completions expected to approximately double in second half, significantly increasing oil mix in 2H17 Raising 3Q17 production guidance from 10.8 to 11.2 MMBoe (29-30% oil) (1) As of August 3, (2) Total Capital Spend is a non-gaap financial measure. Please see the reconciliation of this measure in the Appendix. 6

7 Well Hedged Through 2018 Oil 2H17 Natural Gas 2H17 NGLs 2H17 60% 75% 80% ~70% of expected 2H17 production volumes hedged (1) ~50% of expected 2018 volumes hedged (2) Credit Agreement allows hedging of up to 85% of projected production for the first three years Note: The hedged volumes on this slide do not include any volumes related to basis swaps. (1) At mid-point of revised guidance. (2) Based on February year plan revised to include Divide County production. 7

8 Balance Sheet Financial Position Liquidity of $1.5 billion, including $560MM cash on hand (1) Balance Sheet offers financial flexibility (1) > Senior Secured Debt:TTM Adjusted EBITDAX at ~0.0 times; max ratio allowed 2.75 times > TTM Adjusted EBITDAX:Interest at ~3.9 times; minimum ratio required 2.0 times Debt Maturities (1) (in millions) Corporate ratings: S&P BB-, Moody s B1 $1,000 Commitments and Borrowing base: $925 million Facilities 6% Drilling and $750 (1) Completion Other 8% 86% Other $500 $ % 8% ~$0 drawn $ $ $ $ $ $ $250 $0 Coupon 1.500% 6.500% 6.125% 6.500% 5.000% 5.625% 6.750% Yield to worst (2) 6.45% 6.57% 6.62% 6.28% 6.58% 6.83% Initial call date 11/ /2018 7/2017 7/2018 6/2020 9/2021 Initial call price % % % % % % (1) As of June 30, 2017 (2) As of July 28,

9 Premier Operator of Top-Tier Assets 9

10 Premier Operator Midland Basin Midland Basin Program > Currently operating 7 horizontal rigs Midland Basin ~89,000 net acres > Currently operating 3 completions crews; 9 net completions during 2Q17 RockStar > Production up 8% 1Q17 to 2Q17; RockStar wells significantly outperforming acquisition assumptions > Expect to drill ~100 and complete ~75 gross operated wells during 2017 > Added ~5,400 net acres during first half of 2017 > Better completions driving higher value wells Sweetie Peck Halff East 10

11 Premier Operator Midland Basin Top Operator Well productivity SM ENERGY RANKS #1 BMO data 8/7/17 BMO research Phillip Jungwirth August 7,

12 Outstanding Well Results Based on our in-depth analysis of historic well data we see Howard County as one of the most valuable parts of the Midland Basin given higher oil cuts that decline slower than other areas -Credit Suisse (1) SM Energy best based on operator revenue ranking SM ranks no 1 generating 54% more revenue on an absolute basis than the median peer operator -FBR (2) SM Energy best on revenues per lateral foot SM is the top operator for the most recent year s worth of wells with at least three full months of production data, with revenues per lateral foot 65% better than the median Midland Operator. -FBR (2) (1) Source: Credit Suisse Equity Research, Nitin Kumar, CFA, June 1, 2017; Relaunching US E&P Coverage: Sticking with Asset Quality and Balance Sheet (2) Source: FBR, Joseph Allman, CFA, June 9, 2017; Midland Basin: Operator Productivity and Location Analysis June

13 Premier Operator Midland Basin Applying seismic, core, and geo-chem data to optimize development Modern 3-D Seismic Grid Planned 3-D Seismic Acquisition 13

14 Premier Operator Midland Basin Top assets Howard County Highest oil content, flattest curve HOWARD COUNTY RANKS #1 BMO data 8/7/17 BMO research Phillip Jungwirth August 7,

15 Howard County New Well Results Additional Details 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 % Tackleberry A 1LS LS 7,873 1, day 163 1, , Tackleberry A 1WA WCA 7,861 2, day 288 2, , Tackleberry A 2WB WCB 7,885 1, day 179 1, , Rambo 3846WA (4) WCA 7,546 1, day 150 1, , Rambo 3848WA (5) WCA 7,590 1, day 147 1, , Venkman B 1WA WCA 7,700 1, day 165 1, , Top Gun 1632LS (6) LS 7,711 1, day 165 1, , Top Gun 1652WA (7) WCA 7,595 1, day 218 1, , Guitar North 2722LS (1) LS 9,692 1, day 154 1, , Guitar North 2742WA (2) WCA 9,698 1, day 201 2, , Guitar North 2762WB (3) WCB 9,693 1, day 169 1, , Papagiorgio B 1WA WCA 10,369 1, day 123 1, , Zissou A 15WA WCA 10,315 1, day 131 1, , Viper WA WCA 10,422 1, day 121 1, , Average 1, (1) Name changed from Corinne Elizabeth A 1H (4) Name changed from Rambo WA (7) Name changed from Top Gun 1H (2) Name changed from Corinne Elizabeth A 2H (5) Name changed from Rambo WA (3) Name changed from Corinne Elizabeth A 3H (6) Name changed from Top Gun 2H 15

16 Outstanding Results Howard County Great results in multiple intervals across acreage position Eastland 15 2WH (Apache) Thumper (Sabalo) Guitar North 2722LS IP30: 1,497 BOE/d (87%oil) Interval: Lower Spraberry Lateral Length: 9,692 Guitar North 2742WA IP30: 1,949 BOE/d (90% oil) Interval: Wolfcamp A Lateral Length: 9,698 Guitar North 2762WB IP30: 1,639 BOE/d (87% oil) Interval: Wolfcamp B Lateral Length: 9,693 Mr. Phillips 11-2 #1SH (Sabalo) Iceman 6-well pad (1) Papagiorgio B 1LS Griswold 3-well pad Tubb A 1HA (CrownQuest) Viper WA 24hr IP: 1,316 BOE/d (91% oil) IP30: 1,266 BOE/d (91% oil) Interval: Wolfcamp A Lateral Length: 10,422 Zissou A 15WA IP30: 1,351 BOE/d (92% oil) Interval: Wolfcamp A Lateral Length: 10,315 Papagiorgio B 1WA IP30: 1,275 BOE/d (92% oil) Interval: Wolfcamp A Lateral Length: 10,369 Peer wells SM wells flowing back Martin County Howard County (1) Iceman 6-well pad includes three Wolfcamp A wells and three Lower Spraberry wells. 16

17 Production Rate (BOEPD) Outstanding Results Viper 14-9 WA Viper results to date exceeding expectations 10,000 Viper WA 1, Western Howard County Well Average Days on Production Viper WA Western Howard County Well Average Western Howard County Wells 17

18 Premier Operator Eagle Ford Eagle Ford Program > Currently operating 1 horizontal rig and plan to add a second rig in August > Currently operating 1 completions crew Eagle Ford Operated ~167,500 net acres North Area > Production up 9.5% 1Q17 to 2Q17 (retained properties) East Area > 14 wells completed during 2Q17 South Area > Expect to drill approximately 30 gross wells and complete 39 gross wells during

19 Drilling Cost Per Foot ($/ft) Average Lateral Length (ft) Completion Cost Per Foot ($/ft) Proppant Per Lateral Foot (lb/ft) Premier Operator Eagle Ford Capital efficiency - better wells and lower costs Drilling Costs Completion Costs 500 9,000 1,000 2, , ,000 6,000 5,000 4,000 3,000 2, ,000 1,500 1, , Drilling longer laterals at faster pace, while achieving lower costs > Drilling Cost per foot improved ~30% since 2015 Pumping more sand and fluid into more stages while managing costs > Improving frac designs leads to better wells 19

20 Normalized Gross Cumulative Production (BOE/ft) Outstanding Results Eagle Ford North Outperformance: new generation completion includes tighter stage and cluster spacing with increased fluid per foot Operated Eagle Ford Recent Well Results 2Q17 Completions Q17 Completions Co-development UEF/LEF North Area East Area Wells (A) 1Q17 Completions South Area Wells (B) North Type Curve BOE/FT 1Q17 North Area co-development (A) 2Q17 North Area co-development (B) Days on Production Note: 2-stream data; does not reflect ~ Bbls/MMcf NGL yield for type curve shown. Initial flowback data omitted. 20

21 ~4,000 PRB Creating Value Through Successful JV Tests New completion technology driving 40% improvement in wells Powder River Basin > Utilizing partner services and capital in current development activity (1) Sussex ~10,100 TVD Shannon ~10,750 TVD > ~156,000 total net acres (~114,000 contiguous net acres) > Positive early well results > Frontier and Shannon intervals being tested > Evaluating Niobrara test for early 2018 sizeable inventory potential Well Name LL Reservoir IP Rate (Boe/d) IP Days Cannon 9,462 Frontier 1, Buttermilk 9,199 Frontier 2, Biscuit 9,639 Frontier 2, Gneiss 9,669 Shannon 1, Oil % Tight sand reservoirs Source rock reservoirs Niobrara ~12,000 TVD Frontier ~12,500 TVD Mowry ~13,500 TVD (1) Third party carry to test multiple intervals and newer completion technologies. Initially, SM will realize nominal production and cash flow from these tests. 21

22 SM Energy Why Invest in SM Premier operator of top tier assets Value proposition Doubling cash flow over two years Drilling catalysts Liquidity cash on hand; zero bank debt Drilling catalysts Rapid, high-margin growth Hedging provides stability RockStar wells outperforming 22

23 Appendix 23

24 2nd Quarter and YTD 2017 Performance Solid Execution Production 2Q YTD Total Production (MMBoe) Average Daily Production (MBoe/d) Pre-Hedge Realized Price ($/Boe) $25.13 $26.38 Post-Hedge Realized Price ($/Boe) $26.57 $27.08 Costs LOE ($/Boe) $4.11 $3.96 Ad Valorem ($/Boe) $0.16 $0.36 LOE including Ad Valorem ($/Boe) $4.27 $4.32 Transportation ($/Boe) $5.71 $5.79 Production Taxes (% of pre-derivative oil, gas & NGL revenue) 4.0% 4.1% Total Cash Production Expenses ($/Boe) $10.98 $11.20 Production Margin (pre-hedge) ($/Boe) $14.15 $15.18 G&A Cash ($/Boe) $2.21 $2.15 G&A Non Cash ($/Boe) $0.30 $0.31 Total G&A ($/Boe) $2.51 $2.46 DD&A ($/Boe) $13.52 $

25 2Q17 Regional Realizations Benchmark Pricing NYMEX WTI Oil ($/Bbl) $48.28 NYMEX LLS Oil ($/Bbl) $50.18 NYMEX Henry Hub Gas ($/MMBTU) $3.18 Hart Composite NGL ($/Bbl) $24.11 Production Volumes Eagle Ford Op (1) Permian Rocky Mountain SM Total Oil (MBbls) 356 1, ,909 Gas (MMcf) 29,615 3,362 1,063 34,040 NGL (MBbls) 2, ,755 MBOE 8,005 2,268 1,065 11,338 Revenue (in thousands) Oil $13,072 $78,554 $37,248 $128,874 Gas 87,760 12,937 1, ,770 NGL 53, ,295 Total $154,390 $91,597 $38,951 $284,939 Expenses (in thousands) LOE $13,201 $21,496 $11,865 $46,562 Ad Valorem 1, ,808 Transportation 62, ,760 64,687 Production Taxes 2,781 4,577 3,961 11,319 Per Unit Metrics: Realized Oil/Bbl $36.77 $46.12 $43.81 $44.30 % of Benchmark - WTI 76% 96% 91% 92% Realized Gas/Mcf $2.96 $3.85 $1.01 $2.99 % of Benchmark NYMEX HH 93% 121% 32% 94% Realized NGL/Bbl $19.74 $21.72 $16.97 $19.71 % of Benchmark HART 82% 90% 70% 82% Realized BOE $19.29 $40.38 $36.59 $25.13 LOE/BOE $1.65 $9.48 $11.15 $4.11 Ad Val/BOE $0.21 $0.06 $0.03 $0.16 Transportation/BOE $7.84 $0.08 $1.65 $5.71 Production Tax- per BOE/% of Pre-Hedge Revenue $0.35/1.8% $2.02/5.0% $3.72/10.2% $1.00/4.0% Note: Totals may not sum due to rounding and other classifications (1) Includes nominal amounts of other production and expenses from the region 25

26 2017 Activity Wells Drilled, Flowing Completions & DUC Count Wells Drilled Flowing Completions DUC Count 2nd Quarter YTD 2nd Quarter YTD As of 6/30/17 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 n/a 1 n/a 3 n/a 2 n/a 2 n/a 1 Total n/a 30 n/a 56 n/a 25 n/a 58 n/a 79 (1) Activity in the Powder River Basin is provided by third party services and funding. 26

27 Leasehold Summary As of June 30, 2017 Midland Basin Net Acres (1) 6/30/17 Sweetie Peck 17,255 RockStar (2) 65,950 Halff East (Upton County) 5,985 Midland Basin Total 89,190 Eagle Ford Operated 167,465 Rocky Mountain Divide 121,520 Powder River Basin 156,550 Rocky Mountain Other (3) 187,155 Other Areas/Exploration 24,915 Total 746,795 (1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of June 30, Sweetie Peck acreage includes 2,650 net acres of drill-to-earn acreage. (2) Includes correction from previously reported acreage total. (3) Rocky Mountain Other includes non-core acreage located in North Dakota, Montana, Wyoming, and Utah. 27

28 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 June 30, 2017 Six Months Ended June 30, 2017 Net loss (GAAP) $(119,907) $(45,473) Interest expense 44,595 91,548 Other non-operating income, net (1,265) (1,600) Income tax benefit (71,061) (26,555) Depletion, depreciation, amortization, and asset retirement obligation liability accretion 153, ,044 Exploration (1) 12,077 22,647 Impairment of proved properties 3,806 3,806 Abandonment and impairment of unproved properties Stock-based compensation expense 4,358 9,813 Net derivative gain (55,189) (169,963) Derivative settlement gain 16,303 16,310 Net loss on divestiture activity 167, ,670 Loss on extinguishment of debt - 35 Other (151) 4,835 Adjusted EBITDAX (Non-GAAP) $154,088 $326,274 Interest expense (44,595) (91,548) Other non-operating income, net 1,265 1,600 Income tax benefit 71,061 26,555 Exploration (1) (12,077) (22,647) Amortization of debt discount and deferred financing costs 3,733 8,679 Deferred income taxes (64,015) (30,790) Plugging and abandonment (418) (1,609) Other, net (2,149) (2,581) Changes in current assets and liabilities ,182 Net cash provided by operating activities (GAAP) $107,149 $242,115 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, and gains and losses on divestiture activity. 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 statement of operations for the component of stock-based compensation expense recorded to exploration expense. 28

29 Adjusted Net Loss Reconciliation Reconciliation of net loss (GAAP) to adjusted net loss (non-gaap): (in thousands, except per share data) Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 Net loss (GAAP) $(119,907) $(45,473) Net derivative gain (55,189) (169,963) Derivative settlement gain 16,303 16,310 Net loss on divestiture activity 167, ,670 Impairment of proved properties 3,806 3,806 Abandonment and impairment of unproved properties Loss on extinguishment of debt - 35 Other, net (151) 4,835 Tax effect of adjustments (1) (47,673) 5,469 Adjusted net loss (Non-GAAP) $(35,521) $(55,154) Diluted net loss per common share (GAAP) $(1.08) $(0.41) Net derivative gain (0.50) (1.53) Derivative settlement gain Net 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) 0.05 Adjusted net loss per diluted common share (Non-GAAP) $(0.32) $(0.50) Basic weighted-average common shares outstanding: 111, ,274 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 impairments and losses on sale. 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. 29

30 Total Capital Spend Reconciliation Reconciliation of Costs Incurred in Oil and Gas Activities (GAAP) to Total Capital Spend (Non-GAAP) (1)(3) (in millions) Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 Costs incurred in oil and gas activities (GAAP): $258.0 $515.0 Less: Asset retirement obligation (0.5) (1.4) Less: Capitalized interest (2.9) (5.1) Less: Proved property acquisitions (2) 0.8 (1.4) Less: Unproved property acquisitions (16.5) (75.6) Less: Other (1.6) (1.3) Total capital spend (Non-GAAP): $237.3 $430.2 (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 $76,000 and $887,000 of ARO associated with proved property acquisitions for the three and six months ended June 30, 2017, respectively. (3) The Company completed several primarily non-monetary acreage trades in the Midland Basin during the first half of 2017 totaling $279.8 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. 30

31 Derivative Positions Summary By Quarter Through 2018 As of August 1, 2017 Fixed Swaps Oil Gas NGL (3) Period Volume Volume Volume (MBbls) $/Bbl (1) (BBTU) $/MMBTU (1) (MBbls) $/Bbl (2) 3Q 17 1,340 $ ,657 $4.01 2,019 $ Q 17 1,254 $ ,001 $3.98 1,996 $ Q $ ,628 $3.25 1,829 $ Q $ ,052 $2.85 1,437 $ Q $ ,241 $2.87 1,662 $ Q 18 1,034 $ ,487 $2.90 1,828 $16.54 Collars Period Volume (MBbls) Oil Ceiling $/Bbl (1) Floor $/Bbl (1) 3Q $54.05 $ Q 17 1,086 $56.05 $ Q 18 1,026 $58.46 $ Q 18 1,004 $58.37 $ Q 18 1,393 $57.93 $ Q 18 1,607 $57.75 $50.00 Midland Cushing Oil Basis Swaps Period Volume (MBbls) Price Differential $/Bbl (1) 3Q ($1.62) 4Q 17 1,798 ($1.52) 1Q 18 1,750 ($1.30) 2Q 18 1,371 ($1.42) 3Q 18 1,772 ($1.43) 4Q 18 1,975 ($1.42) Note: Includes all commodity derivative contracts for settlement at any time during the third quarter of 2017 and later periods through 2018, entered into as of 8/1/17. (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. 31

32 NGL Derivative Position Detail (1) NGL Swaps OPIS Eth Purity Mt Belv NGL Swaps OPIS Propane Mt Belv Non-TET NGL Swaps Natural Gasoline Mt Belv Non TET Period Volume (MBbls) $/Bbl (2) 3Q $9.48 4Q $ Total 1,872 Period Volume (MBbls) $/Bbl (2) 3Q $ Q $ Total 1,138 Period Volume (MBbls) $/Bbl (2) 3Q $ Q $ Total 425 1Q $ Q $ Q 18 1,033 $ Q 18 1,146 $ Total 4,017 1Q $ Q $ Q $ Q $ Total 2,021 1Q $ Q $ Q $ Q $ Total 305 NGL Swaps OPIS NButane Mt Belv Non TET Period Volume (MBbls) $/Bbl (2) 3Q $ Q $ Total 312 NGL Swaps OPIS IsoButane Mt Belv Non TET Period Volume (MBbls) $/Bbl (2) 3Q $ Q $ Total 268 1Q $ Q $ Q $ Q $ Total 225 1Q $ Q $ Q $ Q $ Total 188 Note: Totals may not sum due to rounding; reference 10-Q for future period detail (1) Includes all commodity derivative contracts for settlement at any time during the third quarter of 2017 and later periods through 2018 entered into as of August 1, (2) Weighted-Average Contract Price 32

33 NGL Realizations 22% increase in realized price (before hedges) from 2Q16 to 2Q17 SM NGL price realizations are predominately tied to Mont Belvieu, fee based contracts Differential reflects NGL barrel product mix and transportation and fractionation fees 2Q16 3Q16 4Q16 1Q17 2Q17 Mt. Belvieu ($/Bbl) $20.04 $19.74 $24.11 $26.74 $24.11 SM Realization ($/Bbl) % Differential to Mt. Belvieu $16.12 $16.58 $20.02 $22.06 $ % 84% 83% 82% 82% SM Typical NGL Bbl (1) 12% 9% 42% 9% 28% Ethane Propane Iso Butane Normal Butane Pentane (1) Includes the effects of ethane rejection. 33

34 IRR IRR IRR Top-Tier Assets Regional Well Projected Economics 2017 capital program focusing on areas with top tier returns 120% RockStar Wolfcamp A 120% Sweetie Peck Lower Spraberry 100% 100% 80% 80% 60% 40% 20% 60% 40% 20% 0% 0% $40 $45 $50 $55 $60 $40 $45 $50 $55 $60 NYMEX WTI NYMEX WTI 7,600' 10,000' 7,600' 10,000' Well Cost: $5.6MM Well Cost: $6.8MM Well Cost: $5.9MM Well Cost: $7.0MM Well Spacing: 660 Well Spacing: 660 Well Spacing: 660 Well Spacing: 660 Sand loading: 1,900 lbs/ft; Stage Spacing: 167 Sand loading: 1,900 lbs/ft; Stage Spacing: % Eagle Ford East Eagle Ford East ~35% NGLs 80% 60% 40% 1H17 Average Mt. Belvieu ($/Gal) 20% 0% $0.55 $0.60 $0.65 Mt. Belvieu $/Gal Well Cost: $5.2MM, Lateral Length: 8,000, Well Spacing: 625, 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 East oil flat at $50/Bbl WTI. Well economics are not updated to reflect most recent well performance and completion enhancements at 8/1/17. 34

35 Howard County Operators SM Energy Callon Encana Surge/Yantai Xinchao Diamondback Oxy Energen Breitburn Sabalo 35

36 Sweetie Peck Operators SM Energy Apache Chevron Concho Devon Diamondback Discovery Endeavor Exxon Legacy Oxy Pioneer Summit Miscellaneous 36

37 Maverick Eagle Ford Operators Dimmit Dimmit Webb Area North Fasken Area East Area South 37

38 Divide County Operators Canada RE CPEG RE HES CPEG RE MV MV MRX HNT CLR NP Divide Williams CPEG KKN HES CLR 38

39 Powder River Basin Operators Johnson Natrona Campbell Converse SM ENERGY (SME) ANSCHUTZ (ANS) CHESAPEAKE (SHK) DENBURY (DEN) DEVON (DEV) EOG FLEUR DE LIS (FDL) HELIS (HEL) LIBERTY RESOURCES (LIB) SAMSON (SSN) WOLD (WLD) OTHERS 39

40 Contact Information Jennifer Martin Samuels Senior Director, Investor Relations