1Q18 EARNINGS OUTSTANDING EXECUTION

Transcription

1 1Q18 EARNINGS OUTSTANDING EXECUTION MAY 3, 2018

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 forward-looking statements. Forward-looking statements in this presentation include, among other things, full year 2018 guidance, second quarter of 2018 guidance, expectations concerning the planned closing of previously announced divestitures, 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; 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 Non-GAAP forward looking metrics: See Appendix for definitions 2

3 DRIVING DIFFERENTIAL VALUE OFF TO A GREAT START IN 2018 PREMIER OPERATOR TOP TIER ASSETS ~35% C A G R 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 ~35% Credit Suisse 12/11/17 (2) (1) See Appendix for Cash Flow per Debt Adjusted Share definition (2) Betty Jiang and William Featherston, Credit Suisse 3

4 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) Includes closed sale of Powder River Basin assets, and expected proceeds from pending sales of non-core assets in North Dakota and Texas (2) As of March 31, 2018; borrowing base and commitment amount as of May 2,

5 1 ST QUARTER 2018 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) $168.7 MM Discretionary Cash Flow (1) 30% increase (over 4Q17) (1) See Appendix for reconciliation of non-gaap measures 5

6 BALANCE SHEET OFFERS FINANCIAL FLEXIBILITY LIQUIDITY OF $1.6B, INCLUDING $643MM CASH ON HAND (1) Rapidly reducing net debt with expected $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 Borrowing base increased to $1.4B; commitments increased to $1.0B 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 Debt Maturities (1) (in millions) Borrowing Base: $1.4B Commitments: $1.0B $1,500 $1,250 $1,000 $750 $0 drawn $172.5 $ $ $ $ $ $ $500 $250 $0 Coupon 1.500% 6.500% 6.125% 6.500% 5.000% 5.625% 6.750% Yield to worst (2) 5.11% 5.67% 6.23% 5.99% 6.22% 6.38% Initial call date 11/ /2018 7/2017 7/2018 6/2020 9/2021 Initial call price % % % % % % (1) Cash on hand as of March 31, 2018; borrowing base and commitment amount as of May 2, (2) As of April 30,

7 WELL HEDGED PERCENTAGE OF EXPECTED PRODUCTION HEDGED Production Hedged (1) 80% 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% ~70% of expected 2Q18 4Q18 Permian oil production covered by basis hedges at just over $1/Bbl ~1/3 of expected 2019 Permian oil production covered by basis hedges Note: Hedging data as of May 2, 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. 7

8 Production (Boe/d) 2018 PLAN GUIDANCE (1) Capital & Production FY 2018 Total Capital Spend ($MM) (2) (before acquisitions) ~$1,270 Total Production (MMBoe) Total Production (MBoe/d) Oil % ~40% Costs LOE ($/Boe) ~$5.00 Ad Valorem taxes ($/Boe) $0.55 $0.65 Transportation ($/Boe) ~$4.50 Production taxes (% of pre-hedge revenue) % G&A ($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) $13.00 $ Production Guidance by Quarter 1Q18 2Q18e 3Q18e 4Q18e Retained Assets Pending Sale/Sold 2Q18 production guidance MMBoe / MBoe/d (~40% oil) 2Q18 total capital spend expected to be similar to 1Q18 at $367MM; expect to complete ~45 net wells Ad Valorem and Production taxes are expected to be at the higher end of the provided range based on current oil prices (1) As of May 2, 2018 (2) Total Capital Spend is a non-gaap financial measure; reconciliation of this measure is provided in the Appendix. The Company is unable to present a quantitative reconciliation of this forward-looking, non-gaap financial measure without unreasonable effort because acquisition costs are inherently unpredictable. 8

9 ROCKSTAR NEW WELL RESULTS GREAT RESULTS IN MULTIPLE INTERVALS ACROSS ACREAGE POSITION NEW WELLS AVERAGE 1,440 BOE/D, 88% OIL (10,200 LATERAL LENGTH) Fezzik A 2443WA Fezzik A 2444WA Guitar North 2850WA Guitar North 2851WA Guitar North 2852WA Guitar North 2867WB Guitar North 2868WB 30 Day Avg Peak Rate: 1,607 Boe/d (87% oil) Lumbergh 2547WA Lumbergh 2548WA Lumbergh 2565WB 30 Day Avg Peak Rate: 1,536 Boe/d (89% oil) Wiley Bob A 2351WA Wiley Bob 2352WA (1) 30 Day Avg Peak Rate: 941 Boe/d (90% oil) (1) 7,708 lateral length 30 Day Avg Peak Rate: 1,623 Boe/d (85% oil) Lumbergh 2527LS Lumbergh 2528LS 30 Day Avg Peak Rate: 1,485 Boe/d (87% oil) Berlinda Ann 2341WA Berlinda Ann 2342WA Berlinda Ann 2361WB Whitaker Unit 2251WA Whitaker Unit 2252WA 30 Day Avg Peak Rate: 1,305 Boe/d (90% oil) 9

10 Cumulative Production (BOE) ROCKSTAR NEW WELL RESULTS NEW WELLS CONTINUE OUTPERFORMANCE TREND 300, , , , ,000 50, Days on Production (1) (2) Previously Reported Well Avg New Well Avg PEER 1MMBOE 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 11/3/2017. (2) New Well Average includes 19 new wells that have not been previously reported. 10

11 MIDLAND BASIN EXECUTING ON OUR PLAN 17 net completions in 1Q18-15 in RockStar area Midland Basin ~82,500 net acres (1) RockStar 9 rigs currently; expect to reduce to 8 in 2Q18 5 frac fleets operating at high efficiency ~36 net completions expected in 2Q18 Focusing on co-development of intervals Sweetie Peck (1) Excludes acreage related to announced Halff East divestiture that is expected to close during 2Q18. 11

12 EAGLE FORD ENHANCING VALUE OF INVENTORY Eagle Ford ~165,000 net acres 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 12

13 SM ENERGY PREMIER OPERATOR OF TOP TIER ASSETS SUMMARY Excellent execution in 1Q18 On track / ahead of 2018 plan High returns leading to rapid debt-adjusted per share cash flow growth 13

14 Appendix 14

15 Operational Detail 15

16 1Q18 REALIZATIONS BY REGION 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, ,262 Gas (MMcf) 18,731 5, ,222 NGL (MBbls) 1, ,673 MBoe 5,117 4, ,139 Revenue (in thousands) Oil $19,583 $205,794 $35,683 $261,060 Gas 52,733 24,876 1,500 79,109 NGL 41, ,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, ,777 Transportation 45, ,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. 16

17 2018 PLANNED RIG ACTIVITY AND COMPLETIONS BY MONTH 14 Operated Rigs Total Net DUCs (1) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Midland Basin Eagle Ford Total Net DUCs 0 (1) Total Net DUCs counts remove DUCs associated with assets sold / pending sale. 17

18 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 SM Typical NGL Bbl (1) 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 $ % 9% 9% 27% 42% % Differential to Mt. Belvieu 82% 82% 81% 81% 83% Ethane Iso Butane Natural Gasoline Propane Normal Butane (1) Includes the effects of ethane rejection 18

19 2018 ACTIVITY BY REGION WELLS DRILLED, FLOWING COMPLETIONS, AND DUC COUNT Wells Drilled Flowing Completions DUC Count 1 st Quarter st Quarter st Quarter 2018 Region Gross Net Gross Net Gross Net Permian Sweetie Peck RockStar Permian total Eagle Ford (1) Rocky Mountain (Divide) Subtotal Operated Wells Non-operated Wells (3) n/a - n/a - n/a 1 Total n/a 41 n/a 22 n/a 107 (2) (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 19

20 LEASEHOLD SUMMARY PRO-FORMA FOR PENDING TRANSACTIONS Region Midland Basin Net Acres (1) 3/31/18 Pending Sales / Additions Pro-forma Net Acres RockStar 64, ,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 Rocky Mountain Divide 119,235 (119,235) - Rocky Mountain Other (3) 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, (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. 20

21 Financial Detail 21

22 OIL AND GAS DERIVATIVE POSITIONS BY QUARTER THROUGH 2019 Period Midland - Cushing Oil Swaps Oil Collars Oil Basis Swaps Volume Volume (MBbls) $/Bbl (1) (MBbls) Ceiling $/Bbl (1) Floor $/Bbl (1) Volume (MBbls) Price Differential $/Bbl (1) 2Q 18 1,534 $ ,459 $59.03 $ ,392 ($1.03) 3Q 18 1,769 $ ,948 $58.61 $ ,018 ($1.06) 4Q 18 1,894 $ ,222 $58.44 $ ,327 ($1.08) 1Q $ ,865 $61.08 $ ,471 ($1.27) 2Q $ ,990 $61.44 $ ,546 ($1.32) 3Q $ ,079 $61.51 $ ,641 ($1.33) 4Q $ ,092 $61.46 $ ,660 ($1.33) Period Gas Swaps Volume Volume (BBTU) $/MMBTU (1) (BBTU) Gas Collars Ceiling $/MMBTU (1) Floor $/MMBTU (1) 2Q 18 15,712 $ Q 18 17,147 $ Q 18 18,646 $ Q 19 16,979 $ Q ,358 $2.83 $2.50 3Q ,066 $2.83 $2.50 4Q ,818 $2.83 $2.50 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 5/2/18. (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. 22

23 NGL DERIVATIVE SWAP POSITIONS OPIS MT. BELVIEU Period Ethane Purity Volume (MBbls) $/Bbl (2) 2Q $ Q 18 1,033 $ Q 18 1,146 $ Total 3,094 Period Propane Volume (MBbls) $/Bbl (2) 2Q $ Q $ Q $ Total 1,835 Period Iso Butane Volume (MBbls) $/Bbl (2) 2Q $ Q $ Q $ Total 212 1Q $ Q $ Q $ Q $ Total 3,533 1Q $ Q $ Q $ Q $ Total 1,503 1Q $ Q $ Q $ Q $ Total 117 1Q $ Q $ Total 539 Period Natural Gasoline Volume (MBbls) $/Bbl (2) 2Q $ Q $ Q $ Total 585 Period Normal Butane Volume (MBbls) $/Bbl (2) 2Q $ Q $ Q $ Total 279 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 second quarter of 2018 and later periods, entered into as of May 2, (2) Weighted-Average Contract Price 23

24 TOTAL CAPITAL SPEND 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 Note: Amounts may not calculate due to rounding (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. 24

25 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 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. 25

26 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 Note: Amounts may not calculate due to rounding 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, This rate approximates the Company's statutory tax rate adjusted for ordinary permanent differences. 26

27 DISCRETIONARY CASH FLOW 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 Note: Amounts may not calculate due to rounding (1) 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). 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. 27

28 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. 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). 28

29 CONTACT INFORMATION Jennifer Martin Samuels Vice President - Investor Relations jsamuels@sm-energy.com 29