SM Energy (SM) 8-K SM Energy Announces First Quarter 2015 Production

Exhibit 99.2

IPAA OGIS NYC Jay Ottoson President and CEO April 20, 2015

2 Forward Looking Statements - Cautionary Language Except for historical information contained herein, statements in this presentation, including information regarding the business of the Company, contain forward looking statements within the meaning of securities laws, including forecasts and projections. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “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. These risks include factors such as the availability, proximity, and capacity of gathering, processing and transportation facilities; the uncertainty of negotiations to result in an agreement or a completed transaction; the uncertain nature of announced 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 volatility and level of oil, natural gas, and natural gas liquids prices; uncertainties inherent in projecting future rates of production from drilling activities and acquisitions; the imprecise nature of estimating oil and gas reserves; 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 2014 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. .

(1) Economic inventory consists of projects expected to achieve at least a 20% rate of return at 5-yr average strip pricing as of 2/23/15 and expected well costs. 3 Asset and Strategy Overview Williston Basin ~90 MMBOE (net) ~500 gross locations Eagle Ford ~900 MMBOE (net) ~1,050 gross locations Economic inventory(1) of approx. 1.0 BBOE in operated Eagle Ford and Bakken/Three Forks; nearly 20 times 2014 corporate production Potential to increase inventory by more than double without acquisitions Significant existing development inventory How SM Energy will differentially grow shareholder value Operated Programs Industry leading technology application Operational excellence/scale Continue to increase the value and quantity of inventory Focus on debt adjusted per share metrics Preserve financial strength and flexibility Portfolio optimization/ high-grading returns

Financial Position 4 Revolving Credit Facility 6.625% Senior Notes 6.50% Senior Notes Borrowing base reaffirmed at $2.4 billion at the April 2015 redetermination. Strong proved reserve adds at YE14 resulted in a maintained borrowing base in depressed commodity market. 6.125% Senior Notes 6.50% Senior Notes 5.00% Senior Notes $0 $500 $1,000 $1,500 $2,000 $2,500 2024 2023 2022 2021 2020 2019 2019 2018 2017 2016 2015 DEBT MATURITIES AS OF December 31, 2014 (in millions) Borrowing Base - $2.4 billion $166 million drawn

5 2015 Operated Activity Reducing rig activity and building WOC inventory 0 10 20 30 40 50 60 70 80 90 100 0 2 4 6 8 10 12 14 16 18 20 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Wells Waiting on Completion Rigs Eagle Ford Bakken/Three Forks Powder River Basin Permian East Texas WOC inventory

6 2015 Capital Expenditures Total CAPEX budget of $1,230 Op. Eagle Ford $470 Other $185 Bakken/Three Forks $255 Non - Op Eagle Ford $135 (in millions) $1,045 $185 Drilling and Completion Non-drilling and New Ventures

7 Service Costs Coming Down 2015 budget assumed 15% - 20% service cost deflation by year-end. Company-wide costs currently are in-line with budgeted deflation assumptions. Drilling costs currently down 10% - 20%. Completions costs currently down 20% - 25%. Operated EF costs per stage down ~20% from 4Q14 and 25% from 2014 average $- $100 $200 $300 $400 $500 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 D,C&F costs per stage (in thousands) Operated Eagle Ford drill, complete, and facilities costs

8 1Q15 Production Beat Expectations 175.8 186.4 Strong sequential production growth of 6% from 4Q14. Production beat primarily driven by better than expected well performance. Product mix essentially unchanged quarter to quarter. Company plans to revisit guidance after the completion of its Mid-Con asset marketing process. 32% 45% 23% 23% 46% 31% 0 20 40 60 80 100 120 140 160 180 200 4Q14 1Q15e Production (MBOE/d) NGL Gas OIL

9 TEXAS Operated Eagle Ford Program ~144,000 total net acres Dimmit Webb 44.8 48.1 43.0 54.2 56.2 8.2 7.9 7.1 9.7 9.8 23.3 27.2 26.1 29.7 32.1 0 20 40 60 80 100 120 1Q14 2Q14 3Q14 4Q14 1Q15e MBOE/d NGL Oil Gas 76.3 83.2 76.2 93.6 98.1

10 Operated Eagle Ford Type Log Upper EF Lower EF SM Energy has some of the thickest total Eagle Ford Shale interval in the play. Identified several targets within the Upper and Lower Eagle Ford based on facies work. Thickness and geo-mechanical variability presents an opportunity for increased inventory through stacking laterals. Potential Targets Austin Chalk

11 Upper Eagle Ford East Testing Proving up the viability of the Upper Eagle Ford Upper Eagle Ford East results are in-line with Lower Eagle Ford East type curve. Galvan Ranch B311H (Upper EF) Galvan Ranch C314H (Upper EF) East Area Type Curve 0 5 10 15 20 25 30 35 40 45 50 0 2 4 6 8 10 12 2 - STREAM CUMLATIVE PRODUCTION (MBOE/1000’) Producing Months EAST UPPER EAGLE FORD WELLS CUMLATIVE BOE PRODUCTION

12 Upper Eagle Ford North Testing Proving up the viability of the Upper Eagle Ford Briscoe Catarina East 25H (Upper EF) Galvan Ranch LP GU5 State 20H North Area Type Curve (Upper EF) Upper Eagle Ford North results are in-line with Lower Eagle Ford North type curve. 0 5 10 15 20 25 30 35 40 45 0 2 4 6 8 10 12 2 - STREAM CUMULATIVE PRODUCTION (MBOE/1000’) Producing Months NORTH UPPER EAGLE FORD WELLS CUMULATIVE BOE PRODUCTION

13 Eagle Ford Testing Road Map 12 well stacked/staggered 3Q15 completion 3 well stacked/staggered 3Q15 completion 2 well LEF “W” test 2Q15 completion 15 well LEF infill spacing test (625’ & 450’) 2Q15 completion 5 well LEF/UEF “W” test 3Q15 completion Successful stack/stagger development of the Eagle Ford could more than double the current inventory of ~1,050 locations.

14 Williston Basin Acreage Divide Billings Dunn McKenzie Williams Roosevelt Sheridan Gooseneck: ~120,000 net acres Raven/Bear Den: ~40,000 net acres Total Williston Basin acreage: ~245,000 net acres 16.0 16.5 17.5 23.4 23.3 0 5 10 15 20 25 1Q14 2Q14 3Q14 4Q14 1Q15e MBOE/d

15 Gooseneck Sweet Spot Divide Burke Sheridan, MT Williams Decreasing reservoir quality Decreasing reservoir quality Sizeable acreage position in the sweet spot of Divide County, ND The geology deteriorates as you move east and west from the center section of Divide County. Decreasing thermal maturity Increasing water cut

16 Gooseneck Three Forks vs. Offset Divide Gooseneck Three Forks program outperforms offset operators Three Forks Type Curve Offset Operator Results 0 2 4 6 8 10 12 14 16 1 3 5 7 9 11 13 15 17 19 21 23 CUMULATIVE PRODUCTION (MBOE/1000FT ) PRODUCING MONTHS

Gooseneck Bakken Middle Bakken Wells 2015 Planned Bakken Completions Successful development of the Gooseneck Bakken has the potential to double the current inventory of 400 identified Gooseneck Three Forks locations. Three Forks Type Curve Bakken Well Results Bakken wells in Gooseneck are outperforming the Three Forks type curve. 17 0 1 2 3 4 5 6 7 8 0 1 2 3 4 5 6 CUMULATIVE PRODUCTION (MBOE/1000FT) PRODUCING MONTHS

18 Takeaways SM Energy has a strong balance sheet, significant liquidity, and a robust inventory in core programs. Potential to add meaningful inventory in core programs in current pricing environment. Focus is on creating shareholder value and outperforming the peer group.

19 Appendix

20 4Q14 Regional Realizations NYMEX WTI OIL (Bbl) $ 73.16 Hart Composite NGL (Bbl) $ 29.53 NYMEX Henry Hub Gas (MMBTU) $ 3.77 Production Volumes STGC Rockies Mid-Con Permian SM Total Oil (MBbls) 2,164 2,326 27 582 5,099 Gas (MMcf) 34,961 2,239 5,381 1,295 43,876 NGL (MBbls) 3,675 60 25 0 3,760 MBOE 11,666 2,759 949 798 16,172 Revenue (in thousands) Oil $ 136,649 $ 142,082 $ 1,876 $ 38,607 $ 319,214 Gas 135,960 10,327 17,264 6,137 169,691 NGL 95,029 1,870 766 0 97,661 Total $ 367,638 $ 154,279 $ 19,906 $ 44,744 $ 586,566 Expenses LOE $ 29,267 $ 27,706 $ 5,384 $ 12,992 $ 75,299 Transportation $ 88,205 $ 3,640 $ 1,509 $ 31 $ 93,386 Production Taxes $ 8,637 $ 15,815 $ 544 $ 2,506 $ 27,496 Per Unit Metrics: Realized Oil/Bbl $ 63.14 $ 61.09 $ 69.23 $ 66.31 $ 62.60 % of Benchmark – WTI 86 % 84 % 95 % 91 % 86 % Realized Gas/Mcf $ 3.89 $ 4.61 $ 3.21 $ 4.74 $ 3.87 % of Benchmark – NYMEX HH 103 % 122 % 85 % 126 % 103 % Realized NGL/Bbl $ 25.86 $ 30.95 $ 30.60 $ 27.37 $ 25.97 % of Benchmark – HART 88 % 105 % 104 % 93 % 88 % Realized BOE $ 31.51 $ 55.91 $ 20.98 $ 56.07 $ 36.27 LOE/BOE $ 2.51 $ 10.04 $ 5.67 $ 16.28 $ 4.66 Transportation/BOE $ 7.56 $ 1.32 $ 1.59 $ 0.04 $ 5.77 Production Tax - % of Total Revenue 2.3 % 10.3 % 2.7 % 5.6 % 4.7 % * Totals may not sum due to rounding.

Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction from YE14 well costs. Utilizes assumptions from IRR sensitivity using $65/bbl oil. 21 Operated Eagle Ford – East Strong asset continues to provide top-tier returns. Assuming single interval development, SM Energy has identified more than 300 locations on its operated Eagle Ford East area. Webb Mexico Dimmit Economics(2) Well Cost (6,500’ lateral) $5.8MM IRR ~60% NPV10 ~$6.3 MM Current type curve Enhanced well design results 0 10 20 30 40 50 60 70 80 90 100 1 3 5 7 9 11 13 15 17 19 21 23 CUMULATIVE 2 - STREAM PRODUCTION (MBOE/1000FT ) Producing Month 0% 10% 20% 30% 40% 50% 60% 70% $50 $60 $70 NYMEX WTI IRR Sensitivity (1)

Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction from YE14 well costs. Utilizes assumptions from IRR sensitivity using $65/bbl oil. 22 Current type curve Operated Eagle Ford – North Improved completions have enhanced this asset. Assuming single interval development, SM Energy has identified more than 500 locations on its operated Eagle Ford North area. Webb Mexico Dimmit Enhanced well design results Economics (2) Well Cost (8,000’ lateral) $6.5 MM IRR ~30% NPV10 ~$2.6MM 0 10 20 30 40 50 60 1 3 5 7 9 11 13 15 17 19 21 23 CUMULATIVE 2 - STREAM PRODUCTION (MBOE/1000FT ) Production Month 0% 10% 20% 30% 40% $50 $60 $70 NYMEX WTI IRR Sensitivity (1)

23 Operated Eagle Ford – South Wells in southern acreage provide an economic dry gas option. Assuming single interval development, SM Energy has identified more than 200 locations on its operated Eagle Ford South area. Webb Mexico Dimmit Historical well results Represents 25% reduction from YE14 well costs. Utilizes assumptions from IRR sensitivity using $3.50/mmbtu gas. Economics(2) Well Cost (8,000’ lateral) $6.1 MM IRR ~35% NPV10 ~$4.3 MM Current type curve 0 10 20 30 40 50 60 70 1 3 5 7 9 11 13 15 17 19 21 23 CUMULATIVE 2 - STREAM PRODUCTION (MBOE/1000FT ) Producing Months 0% 10% 20% 30% 40% 50% 60% $3.00 $3.50 $4.00 NYMEX Henry Hub IRR Sensitivity (1)

24 Eagle Ford North Stack/Stagger Pilot ~85’ ~120’ 1 PAD Upper and Lower EF development well spacing in targeted facies ~70’ ~175 ft Austin Chalk Upper Eagle Ford Lower Eagle Ford ~200 ft 525’ 263’ 262’ 525’ 525’ ~85’ ~120’ ~110’ 1 PAD

Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction from YE14 well costs. Utilizes assumptions from IRR sensitivity using $65/bbl oil. 25 Gooseneck – Three Forks Under current assumptions, SM Energy has identified more than 400 Three Forks locations on its operated Gooseneck acreage. Divide Williams Substantial remaining inventory in our most economic Williston program. Economics(2) Well Cost (~10,000’ lateral) $4.1 MM IRR ~35% NPV10 ~$2.4 MM Current type curve Enhanced well design results 0 2 4 6 8 10 12 14 16 1 3 5 7 9 11 13 15 17 19 21 23 CUMULATIVE 2 - STREAM PRODUCTION (MBOE/1000FT) Producing months 0% 10% 20% 30% 40% 50% $50 $60 $70 NYMEX WTI IRR Sensitivity (1)

Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction from YE14 well costs. Utilizes assumptions from IRR sensitivity using $65/bbl oil. 26 Raven/Bear Den – Bakken Under current assumptions, SM Energy has identified more than 75 Bakken locations on its operated Raven/Bear Den acreage. Williams McKenzie Economics(2) Well Cost (~10,000’ lateral) $6.8 MM IRR ~30% NPV10 ~$3.1 MM Current type curve Enhanced well design results 0 5 10 15 20 25 1 3 5 7 9 11 13 15 17 19 21 23 CUMULATIVE 2 - STREAM PRODUCTION (MBOE/1000FT ) Producing Month 0% 10% 20% 30% 40% 50% $50 $60 $70 NYMEX WTI IRR Sensitivity (1)