Exhibit 99.1

Barclays Energy-Power Conference Jay Ottoson President and COO September 4, 2014

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,” “target,” “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 2013 Annual Report on Form 10-K. 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. 2

Reserves (MMBOE) Eagle Ford Bakken Other Overview SM Energy is a returns-focused company with core positions in the Eagle Ford and Bakken / Three Forks. 9.8 1.5 2.1 2Q14 Production (MMBOE) 13.4 MMBOE 428.7 MMBOE 3.0 11.1 18.5 30.5 0 5 10 15 20 25 30 2010 2011 2012 2013 MMBOE Eagle Ford Annual Production 0.9 2.1 4.0 5.2 0 1 2 3 4 5 6 2010 2011 2012 2013 MMBOE Bakken / Three Forks Annual Production 77% CAGR 116% CAGR 3

Production Outlook 40 50 60 70 80 2013* 2014 2015 2016 Production (MMBOE) ~20% growth ~20% growth ~15% growth *2013 production for retained properties. Recently increased 2014 production guidance; 2015 annual production growth target increased to ~20% from ~15%. 2015 oil growth expected to be between 30% and 40%. 2016 production growth target set at ~15%. 4

Peer-Leading Corporate Returns 5 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 3-Year Average Cash Return on Average Capital Employed SM Note: Cash return on average capital employed is calculated by SM Energy as GAAP cash flow from operations adjusted for changes in working capital divided by average capital employed. See reconciliation in the Appendix for SM Energy calculation. Data sourced from Bloomberg. Peer group is comprised of the following: CLR, COG, CXO, DNR, EGN, NFX, OAS, PXD, QEP, ROSE, RRC, UPL, WLL, WPX, XCO, and XEC. 5

Operated and non-operated programs are focused on improving and expanding economic drilling inventory. 2014 operated program will utilize longer laterals and increased sand loading completions. Eagle Ford Dimmit Maverick Webb Mexico SM Operated APC Operated. Operated: ~144,000 net acres. Non-operated: ~46,000 net acres 6

SM Energy has decreased its average per well drilling time and increased the consistency of drilling time, leading to lower program costs. Improved Drilling Time 7

Eagle Ford – Area 2 Improvements Recap Area Net Acres 1 35,082 2 21,879 3A 22,226 3B 29,726 4 8,268 5 25,124 6 1,560 Substantial increase in sand loading resulting in: Higher flowing pressures Increased production rates Increased condensate yield 8

Improving Eagle Ford Completions Improved completion design in Area 1 Improved Completions: Average length – 7,032’ @ $8MM/well Average sand loading – 2,046 lbs/ft Old Completions: Average length – 4,396’ @ $6MM/wells Average sand loading – 1,297 lbs/ft SM Energy has increased sand loading and lateral length in its recent Area 1 wells. 9

Improved Completion Design Higher Pressures Area 1: Casing Pressure vs. Cumulative Equivalent Production 10

Improved Completion Design Higher IPs Area 1: Equivalent Rate Per Well vs. Time 11

Improved Completion Design Higher Yield Area 1: Condensate Yield vs. Cumulative Equivalent Production 12

Bakken/Three Forks Operational Highlights During 2Q14, the Company operated 2 rigs in Raven/Bear Den and 1 rig in Gooseneck. Pending acquisition adjacent to Gooseneck adds ~61,000 net acres for $330MM. The Company expects to ramp its basin activity in 4Q14 and 2015. Total Williston Basin net acreage* ~225,000 *Map and acreage total includes pending acquisition acreage. 13

Pending Gooseneck Acquisition Significant acquisition fits perfectly with existing acreage and provides substantial running rooms for this program Upon closing, the Company will have ~97,000 net acres in its Gooseneck focus area. Potential for significant inventory build in Three Forks and Bakken formations. 14

SM Gooseneck vs. Offset Operators Note: Data sourced from North Dakota Industrial Commission website. Plot includes offset operators that have >5 wells in Divide Country, North Dakota. Offset operators include AMZG, MVW, CLR BTE, Murex, and Samson Resources. 15

Powder River Basin Update In 2014, the Company has added approximately 33,000 net acres to its Powder River Basin position. The Company now holds approximately 166,000 net acres in the basin Solid results from Rush State 477-36-1FH: peak 30-day initial production rate of 737 BOE/d from a ~3,800 foot lateral. Increasing activity to accelerate delineation of Frontier interval. The Company has contracted a fourth rig for delivery in 3Q14 and expects to add a fifth rig in 2015. 16

Permian Sweetie Peck Wolfcamp B 30-day rates Avg. 5,000’ lateral well 30-day IP rate: 1,011 BOE/d Avg. 7,6000’ lateral well 30-day IP rate: 1,456 BOE/d Total D&C well costs down 13% since 1/14 Additional bench evaluation looks very encouraging Lower Spraberry Test spud 3Q14 Buffalo Wolfcamp D test is waiting on completion. 17

Strong, Simple Balance Sheet SM Energy’s pro forma debt to trailing twelve-month adjusted EBITDAX is below its peer median average of 2.0x. As of June 30, 2014 Current Revolver Commitments $1.3 billion Revolver drawn $0 First maturity of debt February 2019 * 6/30/14 debt to TTM adjusted EBITDAX was 1.0. Pro forma debt to TTM adjusted EBITDAX includes Gooseneck acquisition. Note: 6/30/14 balance sheet and TTM adjusted EBITDAX data sourced from Bloomberg, Peer group is comprised of, CLR, COG, CXO, DNR, EGN, NFX, OAS, PXD QEP, ROSE, RRC, UPL WLL, WPX XCO, and XEC 18

Key Takeaways Peer-leading corporate returns. Drilling inventory is growing in size and quality. Production growth is continuing and getting oilier. 19

Appendix 20

2Q14 Regional Realizations NYMEX WTI OIL (Bbl) $ 103.06 Hart Composite NGL (Bbl) $ 41.21 NYMEX Henry Hub Gas (MMBTU) $ 4.60 Production Volumes STGC Rockies Mid-Con Permian SM Total Oil (MBbls) 1,673 1,703 15 499 3,893 Gas (MMcf) 30,337 1,495 5,038 1,091 37,961 NGL (MBbls) 3,124 9 27 0 3,160 MBOE 9,854 1,961 881 681 13,380 Revenue (in thousands) Oil $ 150,527 $ 156,868 $ 1,528 $ 48,121 $ 357,274 Gas 143,925 9,562 24,341 7,024 184,852 NGL 111,187 362 980 6 112,535 Total $ 405,639 $ 166,792 $ 26,849 $ 55,151 $ 654,661 Expenses LOE $ 25,313 $ 20,249 $ 4,994 $ 12,219 $ 62,785 Transportation $ 77,559 $ 2,468 $ 2,948 $ 18 $ 82,993 Production Taxes $ 9,978 $ 17,751 $ 893 $ 3,197 $ 31,820 Per Unit Metrics: Realized Oil/Bbl $ 89.96 $ 92.13 $ 100.14 $ 96.37 $ 91.78 % of Benchmark – WTI 87 % 89 % 97 % 94 % 89 % Realized Gas/Mcf $ 4.74 $ 6.39 $ 4.83 $ 6.44 $ 4.87 % of Benchmark – NYMEX HH 103 % 139 % 105 % 140 % 106 % Realized NGL/Bbl $ 35.59 $ 38.45 $ 36.94 $ 29.85 $ 35.61 % of Benchmark – HART 86 % 93 % 90 % 72 % 86 % Realized BOE $ 41.17 $ 85.04 $ 30.46 $ 80.94 $ 48.93 LOE/BOE $ 2.57 $ 10.32 $ 5.67 $ 17.93 $ 4.69 Transportation/BOE $ 7.87 $ 1.26 $ 3.34 $ 0.03 $ 6.20 Production Tax - % of Total Revenue 2.5 % 10.6 % 3.3 % 5.8 % 4.9 % * Totals may not sum due to rounding. CCDD7A95-2418-4A6D-99F1-6475E01CBA4D22 21

Adjusted EBITDAX Reconciliation Adjusted EBITDAX (1) (in thousands) Reconciliation of net income(GAAP) to Adjusted EBITDAX (non-GAAP) to net cash For the Three Months Ended provided by operating activities (GAAP): June 30, 2014 2013 Net income (GAAP) $59,780 $176,522 Interest expense 24,040 21,581 Other non-operating (income) loss, net 1,847 (24) Income tax expense 36,049 46,205 Depletion, depreciation, amortization, and asset retirement obligation liability accretion 187,781 225,731 Exploration (2) 22,603 18,383 Impairment of proved properties 0 34,552 Abandonment and impairment of unproved properties 164 4,339 Stock-based compensation expense 7,997 9,955 Derivative loss (gain) 126,469 (85,190) Cash settlement gain (loss) (33,680) 2,211 Change in Net Profits Plan liability (7,105) (5,438) Gain on divestiture activity (3) (2,526) (6,280) Adjusted EBITDAX (Non-GAAP) $423,419 $342,547 Interest expense ($24,040) ($121,581) Other non-operating (income) loss, net (1,847) 24 Income tax expense (36,049) (46,205) Exploration (2) (22,603) (18,383) Exploratory dry hole expense 6,459 5,727 Amortization of debt discount and deferred financing costs 1,477 1,363 Deferred income taxes 35,537 45,959 Plugging and abandonment (1,894) (2,368) Other (1,724) 3,933 Changes in current assets and liabilities 36,690 3,047 Net cash provided by operating activities (GAAP) $415,425 $314,063 (1) Adjusted EBITDAX represents income before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion, exploration expense, property impairments, non-cash stock compensation expense, derivative loss net of cash settlements, change in the Net Profit Plan liability, and loss on divestitures. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors, 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 facility based on its debt to adjusted EBITDAX ratio. 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, income from operations, net cash provided by operating activities, profitability, or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjsuted EBITDAX amounts presented may not be comparable to similar metrics of other companies. (2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying condensed consolidated statements of operations because of the component of stock-based compensation expense recorded to exploration. (3) Gain on divestiture activity is included within the other operating revenues line item of the accompanying condensed consolidated statements of operations.

Cash Returns on Average Capital Employed Calculation Cash Returns on Average Capital Employed (non-GAAP) (in thousands) For the Years Ending December 31, 2013 2012 2011 2010 Cash flow from operating activities (GAAP) $1,338.5 $922.0 $760.5 $497.1 Changes in working capital (GAAP) (14.8) (10.5) 40.8 5.8 Adjusted cash flow from operating activities (non-GAAP) $1,323.7 $911.5 $801.3 $502.9 Long-term debt (GAAP) $1,600.0 $1,440.0 $985.1 $323.7 Cash (GAAP) (282.2) (5.9) (119.2) (5.1) Net debt (non-GAAP) 1,317.8 1,434.1 865.9 318.6 Stockholder equity (GAAP) 1,606.8 1,414.5 1462.9 1,218.5 Total capital employed (non-GAAP) $2,924.6 $2,848.5 $2,328.8 $1,537.1 Total average capital employed (non-GAAP) $2,886.6 $2,588.7 $1,933.0 Cash return on capital employed (non-GAAP) 46% 35% 41% (Adjusted cash flow from operating /Total average capital employed) Average 3-year cash return on capital employed (non-GAAP) 41% 23