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SM ENERGY CO - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

July 30, 2014

This discussion and analysis contains forward-looking statements. Refer to Cautionary Information about Forward-Looking Statements at the end of this item for an explanation of these types of statements.

Overview of the Company, Highlights, and Outlook

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, oil-focused plays in the Powder River Basin and Permian Basin, and a position in an emerging play in East Texas. We have built a portfolio of onshore properties in the contiguous United States primarily through early entry into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserves growth. Furthermore, by entering these plays early, we believe we can capture larger resource potential at a lower cost. Our principal business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our stockholders while maintaining a strong balance sheet. We strive to leverage industry-leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution, and as appropriate, high-grade our portfolio by selectively divesting assets. We regularly examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength. In the second quarter of 2014, we had the following financial and operational results: Average net daily production for the three months ended June 30, 2014, was 42.8 MBbls of oil, 417.2 MMcf of gas, and 34.7 MBbls of NGLs, for a Company record quarterly equivalent daily



production

rate of 147.0 MBOE, compared with 131.8 MBOE for the same



period in

2013. Please see additional discussion below under Production Results. Net income for the three months ended June 30, 2014, was $59.8 million, or $0.88 per diluted share, compared to net income for the three months ended June 30, 2013, of $76.5 million, or $1.13 per diluted share. Please refer to the Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2014, and 2013 below for additional discussion regarding the components of net income. Costs incurred for oil and gas property acquisitions and



exploration

and development activities for the three months ended June 30, 2014, totaled $677.4 million, which includes approximately $100.0 million related to non-producing property acquisitions in the Powder River Basin. The majority of our drilling and completion costs incurred during this period were in our Eagle Ford shale and



Bakken/Three

Forks programs. Total costs incurred for the same period in 2013 were $500.3 million. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program. Adjusted EBITDAX, a non-GAAP financial measure, for the



three months

ended June 30, 2014, was a Company quarterly record of $423.4 million, compared to $342.5 million for the same period in 2013. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our GAAP net income and net cash provided by operating activities to adjusted EBITDAX. 23

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Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil and condensate are sold using contracts paying us various industry posted prices, most commonly NYMEX West Texas Intermediate ("WTI"). We are paid the average of the daily settlement price for the respective posted prices for the period in which the product is sold, adjusted for quality, transportation, American Petroleum Institute ("API") gravity, and location differentials. Substantially all of our oil production in our South Texas & Gulf Coast region is condensate. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative cash settlements, unless otherwise indicated. The following table summarizes commodity price data, as well as the effects of derivative cash settlements as further discussed under the caption Derivative Activity below, for the first and second quarters of 2014, as well as the second quarter of 2013: For the Three Months Ended June 30, 2014 March 31, 2014 June 30, 2013 Crude Oil (per Bbl): Average daily NYMEX price $ 103.06$ 98.65$ 94.14 Realized price, before the effects of derivative $ 91.78$ 88.96$ 90.00 cash settlements Effects of derivative cash settlements $ (5.18 ) $



(1.85 ) $ (0.36 )

Natural Gas: Average daily NYMEX price (per MMBtu) $ 4.59 $ 5.16$ 4.02 Realized price, before the effects of $ 4.87 $ 5.22$ 4.28 derivatives cash settlements (per Mcf) Effects of derivative cash settlements (per Mcf) $ (0.36 )$ (0.38 )$ (0.05 ) Natural Gas Liquids (per Bbl): Average daily OPIS price $ 41.21$ 45.61$ 37.76 Realized price, before the effects of derivative $ 35.61$ 38.79$ 34.09 cash settlements Effects of derivative cash settlements $ (0.02 ) $



(3.03 ) $ 1.91

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Note: Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products. We expect future prices for oil, gas, and NGLs to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil will continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East. The relative strength of the U.S. dollar compared to other currencies could affect the price of oil. The supply of NGLs in the United States is expected to continue to grow in the near term as a result of the number of industry participants targeting projects that produce these products. If demand does not keep pace with anticipated growth in NGL supply, prices could be negatively impacted. The prices of several NGL products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have been under sustained downward pressure due to high levels of supply in recent years, particularly in the Northeast United States, although cold weather during winter months provided a near term increase in pricing in early 2014. Longer term, we anticipate natural gas prices will remain near current levels. Changes to existing laws and regulations pertaining to the ability to export oil, gas, and NGLs also has the potential to impact the prices for these commodities. The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of July 23, 2014, and June 30, 2014: 24

-------------------------------------------------------------------------------- As of July 23, 2014 As of June 30,



2014

NYMEX WTI oil (per Bbl) $ 98.56 $



101.10

NYMEX Henry Hub gas (per MMBtu) $ 3.83 $ 4.35 OPIS NGLs (per Bbl) $ 39.95 $ 41.10 Derivative Activity We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet and the level of capital commitments and long-term obligations we have in place. With our current derivative contracts, we believe we have established a base cash flow stream for our future operations and have partially reduced our exposure to volatility in commodity prices. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our production. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information regarding our oil, gas, and NGL derivatives. The Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Act") included provisions requiring over-the-counter derivative transactions to be cleared through clearinghouses and traded on exchanges. On July 10, 2012, the Commodity Futures Trading Commission ("CFTC") and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms that determine what types of transactions will be subject to regulation under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect of these new rules on our business and any additional regulations is currently uncertain. Under CFTC rules we believe our derivative activity qualifies for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk entered into by entities predominantly engaged in non-financial activity from the mandatory swap clearing requirement. However, we are not certain whether the provisions of the final rules and regulations will exempt us from the requirements to post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices.



Second Quarter 2014 Highlights and Outlook for the Remainder of 2014

Operational Activities. During the second quarter of 2014, in our operated Eagle Ford shale program in South Texas, we operated five drilling rigs supported by two frac spreads. We were primarily focused on pad drilling in the northern portion of our acreage position where there is a higher liquids contribution to our product mix. Our remaining 2014 program will include various tests of well drilling and completion designs intended to enhance well performance and capital efficiency. We have shifted to drilling longer lateral wells and completing these wells with higher sand concentrations. We believe we have secured the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our current development plans. In our outside operated Eagle Ford shale program, the operator began the second quarter of 2014 running 10 drilling rigs and dropped a rig by the end of the quarter. During the quarter, the remainder of our carry under our Acquisition and Development Agreement with Mitsui E&P Texas LP ("Mitsui"), an indirect subsidiary of Mitsui & Co., Ltd. (the "Acquisition and Development Agreement"), was expended. After completion of the carry, we began paying our full share of drilling and completion costs.



We have an ongoing exploration program to acquire leasehold and test concepts in new plays. In 2014, we are evaluating an emerging new venture play in East Texas. We expect to construct a gathering system later in 2014 to allow for longer-term production tests on wells we have drilled and completed.

25 -------------------------------------------------------------------------------- In our Bakken/Three Forks program, we operated three drilling rigs during the second quarter of 2014 focusing on infill drilling of our Raven/Bear Den and Gooseneck prospects in the North Dakota portion of the Williston Basin. We plan to monitor the results of various well and completion designs and down-spacing tests of both our operated and non-operated properties throughout 2014. Additionally, we plan to test the Bakken interval on our Gooseneck and Stateline acreage during the year. Subsequent to June 30, 2014, we entered into an agreement to acquire approximately 61,000 net acres adjacent to our Gooseneck prospect for approximately $330.0 million. We have been building and accelerating activity in our emerging play in the Powder River Basin in Wyoming throughout 2014. During the second quarter of 2014, we closed on previously announced acquisitions for total cash consideration of approximately $100.0 million. We also added a third drilling rig during the quarter to accelerate the delineation of the play, and we plan to add a fourth operated drilling rig in the third quarter. In our Permian program, we operated two drilling rigs during the second quarter of 2014 focused on horizontal testing and development of the Wolfcamp B interval in our Sweetie Peck prospect. At the end of the second quarter, we spud our first Wolfcamp D test in our Buffalo prospect in the northern Midland Basin. We have approximately 130,000 net acres in the Permian region.



Please refer to Overview of Liquidity and Capital Resources below for additional discussion regarding how we intend to fund our 2014 capital program. Production Results. The table below provides a regional breakdown of our production for the second quarter of 2014:

South Texas & Gulf Coast Rocky Mountain Permian Mid-Continent Total (1) Oil (MMBbl) 1.7 1.7 0.5 - 3.9 Gas (Bcf) 30.3 1.5 1.1 5.0 38.0 NGLs (MMBbl) 3.1 - - 0.1 3.2 Equivalent (MMBOE) 9.9 2.0 0.7 0.9 13.4 Avg. daily equivalents (MBOE/d) 108.3 21.6 7.5 9.7 147.0 Relative percentage 74 % 15 % 5 % 6 % 100 %



____________________________________________

(1) Totals may not add due to rounding.

Our production in the second quarter of 2014 was primarily driven by the continued development of our operated and non-operated Eagle Ford shale programs in our South Texas & Gulf Coast region. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2014, and 2013 below for additional discussion on production. Rocky Mountain Divestiture. In the second quarter of 2014, we completed the divestiture of certain non-strategic assets in the Williston Basin located in our Rocky Mountain region that were classified as held for sale at March 31, 2014. Total divestiture proceeds were $50.2 million. The estimated net gain on this divestiture was $27.8 million. This divestiture is subject to normal post-closing adjustments, which are expected to be completed during the second half of 2014.



Subsequent Events. Subsequent to June 30, 2014, we entered into multiple agreements to acquire producing and non-producing properties in our Rocky Mountain region for a total of approximately $345.0 million. Additionally, we entered into derivative contracts for a total of 4.2 million Bbls of oil production that extend through 2016.

26 -------------------------------------------------------------------------------- First Six Months of 2014 Highlights Production Results. The table below provides a regional breakdown of our first six months of 2014 production: South Texas & Gulf Coast Rocky Mountain Permian Mid-Continent Total (1) Oil (MMBbl) 3.3 3.3 0.9 - 7.5 Gas (Bcf) 58.6 3.0 2.1 9.7 73.5 NGLs (MMBbl) 6.0 - - 0.1 6.1 Equivalent (MMBOE) 19.0 3.9 1.3 1.7 25.9 Avg. daily equivalents (MBOE/d) 105.0 21.3 7.1 9.4 142.8 Relative percentage 73 % 15 % 5 % 7 % 100 %



_____________________________________________

(1) Totals may not add due to rounding.

Please refer to Second Quarter 2014 Highlights and Outlook for the Remainder of 2014 above and Comparison of Financial Results and Trends Between the Six Months Ended June 30, 2014, and 2013 below for additional discussion on production. Costs Incurred in Oil and Gas Producing Activities. For the six months ended June 30, 2014, we incurred $1.0 billion in costs related to oil and gas property acquisitions and exploration and development activities, including both capitalized and expensed amounts. This amount includes approximately $100.0 million related to non-producing property acquisitions in the Powder River Basin. The majority of drilling and completion costs incurred during this period were in our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program. 27



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