News Release

EXHIBIT 99.1

FOR IMMEDIATE RELEASE

February 21, 2018

SM ENERGY REPORTS 2017 RESULTS AND 2018 OPERATING PLAN:

PERMIAN EXECUTION OUTSTANDING, CASH FLOW GROWTH AHEAD

Denver, Colorado February 21, 2018 - SM Energy Company ("SM Energy" or the “Company”) (NYSE: SM) today announces fourth quarter and full year 2017 financial and operating results, year-end 2017 reserves and the Company’s 2018 operating plan. Highlights include:

•	2017 net production totaled 44.5 MMBoe, delivering 165% production growth from top tier Midland Basin assets and 47% operating margin growth per Boe 4Q16 to 4Q17 as the Company successfully continues its portfolio transition.

•	2017 year-end proved reserves increased to 468 MMBoe, adding 47% reserve growth on a retained asset basis, nearly tripling Midland Basin reserves and increasing the standardized measure of discounted future net cash flows by 2.5 times from $1.2B to $3.0B.

•	2018-2019 operating plan targets competitive growth in debt adjusted cash flow and aligns expected total capital spend with expected cash flow by mid-year 2019.

•	Outstanding performance from new wells in Howard County ranks SM top Midland Basin operator by revenue per well and results in significant value creation on RockStar properties. New RockStar wells announced today include two Maverick pad wells with 30-day IP rates that each approximated 200 Boe/d per 1,000 lateral feet, continuing the Company’s strong performance record.

MANAGEMENT COMMENTARY

President and Chief Executive Officer Jay Ottoson comments: “At this time last year we set forth an aggressive three-year plan to grow debt adjusted cash flow --our preferred measure of returns-- implementing a strategy that included driving value creation on our newly acquired Howard County assets through optimizing drilling and completion operations, generating margin expansion through a capital program focused on growth on our Midland Basin assets, and further coring up our portfolio to maximize the present value of assets and de-lever the balance sheet. 2017 was a highly successful year in meeting and exceeding our announced objectives, and I thank our SM team across the board for successful execution.

“We commence 2018 well positioned to continue this strategy and meet our planned growth trajectory. While 2017 was a transitional year for production and cash flow growth, 2018 and 2019 target substantial growth in cash flow along with a reduction in net debt:EBITDAX to approximately 2.5 times. This year we move into development mode on our RockStar assets. We have increased the rig count in the Midland Basin from four in early 2017 to nine currently, while continuing to demonstrate top tier efficiency metrics. I believe our operations are top tier as is our asset base, and we look forward to generating increased value for our shareholders in 2018 and beyond.”

"Lastly, I want to congratulate Jennifer Martin Samuels on her well deserved promotion to Vice President - Investor Relations in recognition of her outstanding work in leading our investor relations efforts."

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2017 IN REVIEW

YEAR-END 2017 PROVED RESERVES

Year-end 2017 proved reserves of 468 MMBoe are calculated in accordance with SEC pricing at $51.34 per barrel of oil NYMEX, $3.00 per MMBtu of natural gas at Henry Hub, and $27.69 per barrel of NGLs at Mt. Belvieu. Year-end proved reserves were 34% oil, 20% NGLs and 46% natural gas. Proved reserves were 46% proved developed.

•	Adjusting year-end 2016 reserves for divestitures, proved reserves increased 47% on a retained asset basis.

•	Net proved reserve additions were 192 MMBoe, or 4.3 times production.

•	Midland Basin proved reserves nearly tripled to 160 MMBoe.

The table below provides a reconciliation of changes in the Company’s proved reserves from year-end 2016 to year-end 2017 (numbers are rounded):    

Proved reserves year-end 2016 (MMBoe)	396
Divestitures completed in 2017	(76)
Proved reserves 2016 pro forma sold properties	320
Production	(44)
Reserve additions from drilling and performance	182
Reserve additions through acquisition	1
Reserve revisions net of price and 5-year rules	9
Proved reserves year-end 2017 (MMBoe)	468

Proved reserves at year-end include approximately 4.2 MMBoe associated with the announced agreement to sell certain Powder River Basin assets.

The standardized measure of discounted future net cash flows was $3.0 billion at year-end 2017, up from $1.2 billion at year-end 2016. PV-10 (a non-GAAP measure, reconciled to the standardized measure, see Financial Highlights below) was up more than 2.5 times at $3.1 billion at year-end 2017, compared with $1.2 billion at year-end 2016.

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FOURTH QUARTER AND FULL YEAR RESULTS

See the Financial Highlights section below for production and per Boe detail, summary financial statements and non-GAAP reconciliations.

Production volumes for the fourth quarter and full year 2017 were:

PRODUCTION
	Fourth Quarter 2017			Full Year 2017
Oil (MMBbls)	3.9			13.7
Natural gas (Bcf)	26.0			123.0
NGLs (MMBbls)	2.2			10.3
Total MMBoe	10.4			44.5

By region:

REGIONAL PRODUCTION
	Fourth Quarter 2017		Full Year 2017
Eagle Ford	6.0		29.5
Permian Basin	3.6		11.0
Rocky Mountain	0.8		4.1
Total MMBoe	10.4		44.5

•	Amounts may not calculate due to rounding

•	Eagle Ford includes nominal other production from the region; full year includes non-operated Eagle Ford production prior to divestiture

•	For purposes of 2017 presentation, retained assets include Powder River Basin assets expected to be sold in 2018

•	Production increased 2% and 8% for the fourth quarter and full year, respectively, compared with the prior year periods on a retained asset basis.

•	Oil production increased 51% and 52% for the fourth quarter and full year, respectively, compared with the prior year periods on a retained asset basis.

•	Production in the fourth quarter reflects strong 21% sequential growth in Permian Basin volumes, which was more than offset by lower sequential Eagle Ford volumes as a result of the previously announced joint venture as well as natural declines, as no new wells were completed in the Eagle Ford during the quarter.

Realized prices (before and after the effect of derivative settlements) for the fourth quarter and full year 2017 were:

COMMODITY PRICES
	4Q17 Pre/post Hedge		Full Year 2017 Pre/post Hedge
Oil - $/Bbl	53.32/48.90		47.88/45.60
Natural gas - $/Mcf	3.09/4.03		3.00/3.72
NGLs - $/Bbl	26.01/18.84		22.35/18.91
Boe - $/Boe	32.95/32.16		28.20/28.68

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•

Pre-hedge realized prices of $32.95 per Boe and $28.20 per Boe for the two periods presented were up 27% and 32%, respectively, from the prior year periods demonstrating the revenue benefit from increasing the proportion of production from the oil-rich Midland Basin and improved benchmark commodity prices. Oil, natural gas and NGL revenue was up in 2017 versus 2016, despite a 20% decline in total production.

•	Cash derivative settlements for NGLs were a loss of $15.8 million in the fourth quarter, as the benchmark NGL price jumped to a 13-quarter high.

Operating costs for the fourth quarter and full year were:

OPERATING COSTS $ PER BOE
	Fourth Quarter 2017				Full Year 2017
Total LOE, incl. ad valorem tax	$	5.43			$	4.77
Transportation	5.01				5.48
Production tax	1.41				1.18
General and administrative	3.38				2.71
Total	$	15.23			$	14.14

•	General and administrative costs include $0.69 and $0.43 for the fourth quarter and full year, respectively, for non-cash expenses.

•

Overall, production costs are influenced by the commodity mix as oil production from the Midland Basin increases and natural gas and NGL production from the Eagle Ford decreases, relative to the total production mix. LOE costs increase because lifting costs are higher for oil, and transportation costs decrease because higher cost third party transportation contracts relate to Eagle Ford natural gas and NGLs. Each quarter of 2017, LOE costs trended higher partially offset by transportation costs that trended lower.

•	Fourth quarter of 2017 LOE costs included road work required following the Texas storms.

NET LOSS AND LOSS PER SHARE

The Company’s GAAP net loss for the fourth quarter of 2017 was $26.3 million or $0.24 per diluted common share compared with the fourth quarter of 2016 net loss of $200.9 million, or $2.20 per diluted common share. For the full year 2017, net loss was $160.8 million, or $1.44 per diluted common share, compared with a net loss in 2016 of $757.7 million or $9.90 per diluted common share.

•	The operating margin (before the effects of derivative settlements) per Boe was up 71% in 2017 compared with 2016, reflecting the portfolio transition to increased Midland Basin oil production, higher benchmark prices and a continued focus on controlling costs.

•	The greater net loss in 2016 was predominantly driven by impairment and abandonment charges in 2016 totaling $435 million and higher depletion, depreciation and amortization charges.

•	Fourth quarter and full year 2017 net loss includes a one-time tax benefit of $63.7 million (included in Income tax benefit) related to a reduction in deferred taxes as a result of the changed corporate income tax rate under US tax reform.

Net cash provided by operating activities was $144.8 million in the fourth quarter of 2017 and $515.4 million for the full year 2017.

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ADJUSTED EBITDAX AND ADJUSTED NET INCOME

Adjusted EBITDAX, adjusted net income (loss) and adjusted net income (loss) per diluted common share are non-GAAP measures. Please reference the reconciliations to the most directly comparable GAAP financial measures in the Financial Highlights section at the end of this release.

The Company’s adjusted EBITDAX for the fourth quarter of 2017 was $174.0 million, compared with $186.2 million in the prior year period. For the full year 2017, adjusted EBITDAX was $664.7 million, compared with $790.8 million in the prior year.

•	Fourth quarter adjusted EBITDAX included an accrual of $5 million in other expense that was a non-recurring charge.

The Company’s adjusted net loss for the fourth quarter was $8.5 million, or $0.08 per diluted common share, compared with adjusted net loss of $28.7 million, or $0.31 per diluted common share, in the fourth quarter of 2016. For the full year 2017, adjusted net loss was $91.2 million, or $0.82 per diluted common share, compared with adjusted net loss of $142.4 million or $1.86 per diluted common share in 2016.

•	Fourth quarter adjusted net loss removes the one-time tax benefit of $63.7 million and one-time charge of $5 million, each discussed above, as well as other items that are non-recurring or difficult to estimate.

FINANCIAL POSITION AND LIQUIDITY

At December 31, 2017, the outstanding principal balance on the Company’s long-term debt was $2.8 billion in senior notes plus $172.5 million in senior convertible notes, with zero drawn on the Company’s senior secured credit facility. The Company’s undrawn credit facility plus cash on hand provided $1.2 billion in liquidity at December 31, 2017.

COSTS INCURRED AND TOTAL CAPITAL SPEND

Total capital spend discussed below is a non-GAAP measure and is defined as costs incurred less ARO, capitalized interest and acquisitions. See the Financial Highlights section below for the GAAP reconciliation.

Costs incurred for 2017 were $1,040 million, which included $80.2 million of proved and unproved property acquisitions. Full year 2017 total capital spend was $936 million. Allocated by region, total capital spend was invested 78% in the Permian Basin, 18% in the Eagle Ford, and 4% in the Rocky Mountain region. Allocated by expenditure, total capital spend was invested 88% in development, 5% in infrastructure, 1% in leasehold and 6% in corporate and exploration costs.

•	During 2017, the Company drilled 123 net wells, of which 98 were in the Permian Basin, 24 were in the Eagle Ford and 1 was in the Powder River Basin.

•	During 2017, the Company completed 111 net wells, of which 73 were in the Permian Basin, 35 were in the Eagle Ford and 3 were in the Rocky Mountain area.

•	During the fourth quarter of 2017, the Company added one rig and one completions crew to its Midland Basin program.

•

Fourth quarter total capital spend was higher than forecast. A fourth Permian completions crew was added earlier than originally planned during the quarter, which enabled the Company to secure an experienced crew and increase the expected number of flowing completions for the first quarter of 2018. Total capital spend was also affected by acceleration of facilities to keep pace with completions. In addition, drilling and completion costs increased per well as a result of employing enhanced

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completion technologies and cost inflation, as cost escalators tied to oil prices in certain contracts began to take effect.

2018 OPERATING PLAN AND GUIDANCE

The Company’s objective is to deliver competitive long-term growth in debt adjusted cash flow. Over the next two years, it is the Company’s goal to generate substantial growth in cash flow, end 2019 with net debt:EBITDAX approximating 2.5 times and exit 2019 positioned to deliver continued cash flow growth while keeping total capital spend aligned with cash flow. The Company’s two-year strategy to meet these objectives includes:

•	generating substantial growth in high-margin Permian production

•	maintaining the Company’s operational excellence and top tier capital efficiency

•	continuing to demonstrate the value proposition of the RockStar acquisitions; and

•	managing the balance sheet as measured by ample liquidity, declining net debt:EBITDAX and absolute debt reduction.

Key assumptions in the Company's 2018 operating plan include:

•	Total capital spend of approximately $1.27 billion.

◦	Cost inflation for drilling and completions services per lateral foot of 10%-15% over average 2017 costs.

◦	Permian -- Expect to drill approximately 130 net wells and complete approximately 100 net wells.

◦

Eagle Ford -- Expect to drill approximately 17 net wells and complete approximately 25 net wells. The Company’s JV counterparty is expected to pay the costs to complete 16 wells, which the Company expects will effectively fund a significant portion of the Company’s leasehold development obligations in the Eagle Ford. Fewer net completions for the year are expected to result in lower Eagle Ford production in 2018 compared to the fourth quarter of 2017 run rate.

◦	Total capital spend is weighted to the first half of 2018 as the rig and completion crew count in the Midland Basin is expected to be reduced from 9 and 5, respectively, in the first quarter to 7 and 3, respectively, at year-end.

◦	Rocky Mountain -- Nominal capital allocation.

◦	Facilities - Approximately $130 million, of which more than one-half relates to building fresh and produced water infrastructure in the RockStar area (including associated land costs). This investment is expected to enable acceleration and control of needed facilities while significantly reducing future per well capital costs and operating expenses.

◦	Capitalized overhead/exploration - $70-75 million.

•	Average commodity price projections:

◦	2018 WTI oil $57.40 (1Q18 at $64.70 and remainder of 2018 at $55.00 flat), Henry Hub natural gas $3.00, and NGLs 50% of WTI.

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•	Asset divestiture timing: The PRB sale is expected to close at the end of the first quarter, and as a result, production volumes are removed starting April 2018, but there can be no assurance that this transaction will close on time or at all.

•	Hedges: Based on the production guidance mid-point, the Company has hedges in place for approximately 75% of 2018 oil production and 65% of 2018 natural gas production. NGL production is hedged by product and includes ethane, propane, butanes and natural gasoline.

Full Year 2018 Guidance:

Total capital spend (before acquisitions) is a non-GAAP measure. 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.

•	Total capital spend: ~$1.27 billion.

•	Production: 42-46 MMBoe, with oil approximately 41% of the commodity mix.

•	LOE: ~$5.00 per Boe average for the year, reflecting a higher proportion of oil in the commodity mix. It is expected that 1H18 will exceed the annual average and 2H18 to be below the annual average, as Permian costs are expected to be reduced with the planned completion of produced water handling systems.

•	Transportation: ~$4.50 per Boe average for the year, expected to decline sequentially through the year as higher cost Eagle Ford production is a reduced proportion of the commodity mix. It is expected that 1H18 will exceed the annual average and 2H18 be below the annual average.

•	Production taxes: ~$1.55 per Boe or 4.0-4.5% of pre-hedge revenue.

•	Ad Valorem taxes: $0.55-0.65 per Boe

•	G&A: $125-135 million, including approximately $20 million of non-cash compensation.

•	Capitalized overhead/exploration: $70-75 million, before dry hole expense, all of which is included in capital expenditure guidance.

•	DD&A: $13.00-15.00 per Boe.

First quarter of 2018 Guidance:

•	Production of approximately 9.5-10.0 MMBoe, with oil production approaching 40% of commodity mix.

◦	Lower sequential production from the fourth quarter of 2017 is driven by declines in the Eagle Ford, where no new wells were completed in the fourth quarter of 2017, and declines in the Rocky Mountain region.

•	Completion of approximately 18 net wells in the Midland Basin and 5 net wells in the Eagle Ford during the quarter.

•	Total capital spend of approximately $350 million, which includes approximately $40 million allocated to facilities and land, which is largely associated with construction of RockStar fresh and produced water infrastructure.

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OFFICER APPOINTMENT

On February 16, 2018, the Board of Directors of the Company appointed Jennifer Martin Samuels to Vice President - Investor Relations.

UPCOMING EVENTS

EARNINGS WEBCAST AND CALL

As previously announced, SM Energy is posting a pre-recorded discussion and presentation in conjunction with this earnings release. Please look for the additional detail on the Company's website at www.sm-energy.com. Tomorrow morning, the Company will host an associated Q&A session via webcast and conference call. Please join management February 22, 2018 at 8:00 a.m. Mountain Time/10:00 a.m. Eastern Time. Join us via webcast at www.sm-energy.com or by telephone 877-870-4263 (toll free) or 412-317-0790 (international), and indicate SM Energy earnings call. The webcast and call will also be available for replay. The dial-in replay number is 877-344-7529 (toll free) or 412-317-0088, and the replay access code is 10116628.

UPCOMING CONFERENCE PARTICIPATION

The Company is not scheduled to participate in any industry conferences during the first quarter of 2018.

FORWARD LOOKING STATEMENTS

This release contains forward-looking statements within the meaning of securities laws. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “guidance,” "pending," “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 release include, among other things, full year 2018 guidance, first quarter of 2018 guidance, expectations concerning the planned closing of a previously announced divestiture, 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; the uncertain nature of acquisition, divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions (including any delay in the Company's pending Powder River Basin asset divestiture as a result of litigation); the uncertain nature of expected benefits from the actual or expected acquisition, divestiture, joint venture, 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

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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.

ABOUT THE COMPANY

SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids in onshore North America. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at www.SM-Energy.com.

SM ENERGY CONTACTS

INVESTORS: Jennifer Martin Samuels, jsamuels@sm-energy.com, 303-864-2507

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
	For the Three Months Ended December 31,											For the Twelve Months Ended December 31,
Production Data:	2017				2016				Percent Change			2017				2016				Percent Change
Average realized sales price, before the effects of derivative settlements:
Oil (per Bbl)	$	53.32			$	43.58			22	%		$	47.88			$	36.85			30	%
Gas (per Mcf)	$	3.09			$	2.86			8	%		$	3.00			$	2.30			30	%
NGL (per Bbl)	$	26.01			$	20.02			30	%		$	22.35			$	16.16			38	%
Equivalent (per BOE)	$	32.95			$	25.86			27	%		$	28.20			$	21.32			32	%
Average realized sales price, including the effects of derivative settlements:
Oil (per Bbl)	$	48.90			$	48.96			—	%		$	45.60			$	51.48			(11	)%
Gas (per Mcf)	$	4.03			$	3.21			26	%		$	3.72			$	2.94			27	%
NGL (per Bbl)	$	18.84			$	16.92			11	%		$	18.91			$	15.56			22	%
Equivalent (BOE)	$	32.16			$	27.59			17	%		$	28.68			$	27.28			5	%
Production:
Oil (MMBbls)	3.8				4.0				(5	)%		13.7				16.6				(18	)%
Gas (Bcf)	26.0				35.2				(26	)%		123.0				146.9				(16	)%
NGL (MMBbls)	2.2				3.5				(37	)%		10.3				14.2				(27	)%
MMBOE (6:1)	10.4				13.4				(23	)%		44.5				55.3				(20	)%
Average daily production:
Oil (MBbls/d)	41.5				43.9				(5	)%		37.4				45.4				(17	)%
Gas (MMcf/d)	282.5				382.7				(26	)%		337.0				401.5				(16	)%
NGL (MBbls/d)	24.0				37.9				(37	)%		28.2				38.8				(27	)%
MBOE/d (6:1)	112.6				145.6				(23	)%		121.8				151.0				(19	)%
Per BOE Data:
Realized price before the effects of derivative settlements	$	32.95			$	25.86			27	%		$	28.20			$	21.32			32	%
Lease operating expense	5.10				3.67				39	%		4.43				3.51				26	%
Transportation costs	5.01				6.39				(22	)%		5.48				6.16				(11	)%
Production taxes	1.41				1.11				27	%		1.18				0.94				26	%
Ad valorem tax expense	0.33				0.17				94	%		0.34				0.21				62	%
General and administrative	3.38				2.49				36	%		2.71				2.29				18	%
Operating profit, before the effects of derivative settlements	$	17.72			$	12.03			47	%		$	14.06			$	8.21			71	%
Derivative settlement gain (loss)	(0.79		)		1.73				(146	)%		0.48				5.96				(92	)%
Operating profit, including the effects of derivative settlements	$	16.93			$	13.76			23	%		$	14.54			$	14.17			3	%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	12.69			$	12.81			(1	)%		$	12.53			$	14.30			(12	)%

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Balance Sheets
(in thousands, except share data)	December 31,				December 31,
ASSETS	2017				2016
Current assets:
Cash and cash equivalents	$	313,943			$	9,372
Accounts receivable	160,154				151,950
Derivative assets	64,266				54,521
Prepaid expenses and other	10,752				8,799
Total current assets	549,115				224,642
Property and equipment (successful efforts method):
Proved oil and gas properties	6,139,379				5,700,418
Less - accumulated depletion, depreciation, and amortization	(3,171,575		)		(2,836,532		)
Unproved oil and gas properties	2,047,203				2,471,947
Wells in progress	321,347				235,147
Oil and gas properties held for sale, net	111,700				372,621
Other property and equipment, net of accumulated depreciation of $49,985 and $42,882, respectively	106,738				137,753
Total property and equipment, net	5,554,792				6,081,354
Noncurrent assets:
Derivative assets	40,362				67,575
Other noncurrent assets	32,507				19,940
Total other noncurrent assets	72,869				87,515
Total assets	$	6,176,776			$	6,393,511
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	386,630			$	299,708
Derivative liabilities	172,582				115,464
Total current liabilities	559,212				415,172
Noncurrent liabilities:
Revolving credit facility	—				—
Senior Notes, net of unamortized deferred financing costs	2,769,663				2,766,719
Senior Convertible Notes, net of unamortized discount and deferred financing costs	139,107				130,856
Asset retirement obligations	103,026				96,134
Asset retirement obligations associated with oil and gas properties held for sale	11,369				26,241
Deferred income taxes	79,989				315,672
Derivative liabilities	71,402				98,340
Other noncurrent liabilities	48,400				47,244
Total noncurrent liabilities	3,222,956				3,481,206
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,687,016 and 111,257,500 shares, respectively	1,117				1,113
Additional paid-in capital	1,741,623				1,716,556
Retained earnings	665,657				794,020
Accumulated other comprehensive loss	(13,789		)		(14,556		)
Total stockholders’ equity	2,394,608				2,497,133
Total liabilities and stockholders’ equity	$	6,176,776			$	6,393,511

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Statements of Operations
(in thousands, except per share data)	For the Three Months Ended December 31,								For the Twelve Months Ended December 31,
	2017				2016				2017				2016
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	341,187			$	346,296			$	1,253,783			$	1,178,426
Net gain (loss) on divestiture activity	537				33,661				(131,028		)		37,074
Other operating revenues, net	(1,186		)		(57		)		6,621				1,950
Total operating revenues and other income	340,538				379,900				1,129,376				1,217,450
Operating expenses:
Oil, gas, and NGL production expense	122,833				151,907				507,906				597,565
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	131,393				171,552				557,036				790,745
Exploration(1)	16,886				23,699				56,179				65,641
Impairment of proved properties	—				76,780				3,806				354,614
Abandonment and impairment of unproved properties	12,115				74,450				12,272				80,367
General and administrative (including stock-based compensation)(1)	35,021				33,311				120,585				126,428
Net derivative loss(2)	115,778				129,547				26,414				250,633
Other operating expenses	7,364				3,041				13,667				10,772
Total operating expenses	441,390				664,287				1,297,865				2,276,765
Loss from operations	(100,852		)		(284,387		)		(168,489		)		(1,059,315		)
Non-operating income (expense):
Interest expense	(43,618		)		(46,356		)		(179,257		)		(158,685		)
Gain (loss) on extinguishment of debt	—				—				(35		)		15,722
Other, net	1,067				130				3,968				362
Loss before income taxes	(143,403		)		(330,613		)		(343,813		)		(1,201,916		)
Income tax benefit	117,145				129,667				182,970				444,172
Net loss	$	(26,258	)		$	(200,946	)		$	(160,843	)		$	(757,744	)
Basic weighted-average common shares outstanding	111,611				91,440				111,428				76,568
Diluted weighted-average common shares outstanding	111,611				91,440				111,428				76,568
Basic net loss per common share	$	(0.24	)		$	(2.20	)		$	(1.44	)		$	(9.90	)
Diluted net loss per common share	$	(0.24	)		$	(2.20	)		$	(1.44	)		$	(9.90	)
(1) Non-cash stock-based compensation component included in:
Exploration expense	$	2,402			$	1,410			$	6,300			$	6,447
General and administrative expense	$	5,021			$	5,002			$	17,283			$	20,450
(2) The net derivative loss line item consists of the following:
Settlement (gain) loss	$	8,168			$	(23,244	)		$	(21,234	)		$	(329,478	)
Loss on fair value changes	107,610				152,791				47,648				580,111
Net derivative loss	$	115,778			$	129,547			$	26,414			$	250,633

12

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Statements of Stockholders' Equity
(in thousands, except share data and dividends per share)								Additional Paid-in Capital								Accumulated Other Comprehensive Loss				Total Stockholders’ Equity
	Common Stock											Retained Earnings
	Shares			Amount
Balances, January 1, 2015	67,463,060			$	675			$	283,295			$	2,013,997			$	(11,312	)		$	2,286,655
Net loss	—			—				—				(447,710		)		—				(447,710		)
Other comprehensive loss	—			—				—				—				(2,090		)		(2,090		)
Cash dividends, $ 0.10 per share	—			—				—				(6,772		)		—				(6,772		)
Issuance of common stock under Employee Stock Purchase Plan	197,214			2				4,842				—				—				4,844
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	375,523			4				(8,682		)		—				—				(8,678		)
Stock-based compensation expense	39,903			—				27,467				—				—				27,467
Other	—			—				(1,315		)		—				—				(1,315		)
Balances, December 31, 2015	68,075,700			$	681			$	305,607			$	1,559,515			$	(13,402	)		$	1,852,401
Net loss	—			—				—				(757,744		)		—				(757,744		)
Other comprehensive loss	—			—				—				—				(1,154		)		(1,154		)
Cash dividends, $ 0.10 per share	—			—				—				(7,751		)		—				(7,751		)
Issuance of common stock under Employee Stock Purchase Plan	218,135			2				4,196				—				—				4,198
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	199,243			2				(2,356		)		—				—				(2,354		)
Stock-based compensation expense	53,473			1				26,896				—				—				26,897
Issuance of common stock from stock offerings, net of tax	42,710,949			427				1,382,666				—				—				1,383,093
Equity component of 1.50% Senior Convertible Notes due 2021 issuance, net of tax	—			—				33,575				—				—				33,575
Purchase of capped call transactions	—			—				(24,195		)		—				—				(24,195		)
Other	—			—				(9,833		)		—				—				(9,833		)
Balances, December 31, 2016	111,257,500			$	1,113			$	1,716,556			$	794,020			$	(14,556	)		$	2,497,133
Net loss	—			—				—				(160,843		)		—				(160,843		)
Other comprehensive income	—			—				—				—				767				767
Cash dividends, $0.10 per share	—			—				—				(11,144		)		—				(11,144		)
Issuance of common stock under Employee Stock Purchase Plan	186,665			2				2,621				—				—				2,623
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	171,278			1				(1,241		)		—				—				(1,240		)
Stock-based compensation expense	71,573			1				22,699				—				—				22,700
Cumulative effect of accounting change	—			—				1,108				43,624				—				44,732
Other	—			—				(120		)		—				—				(120		)
Balances, December 31, 2017	111,687,016			$	1,117			$	1,741,623			$	665,657			$	(13,789	)		$	2,394,608

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Statements of Cash Flows
(in thousands)	For the Three Months								For the Twelve Months
	Ended December 31,								Ended December 31,
	2017				2016				2017				2016
					(as adjusted)								(as adjusted)
Cash flows from operating activities:
Net loss	$	(26,258	)		$	(200,946	)		$	(160,843	)		$	(757,744	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net (gain) loss on divestiture activity	(537		)		(33,661		)		131,028				(37,074		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	131,393				171,552				557,036				790,745
Exploratory dry hole expense	2,381				—				2,381				(16		)
Impairment of proved properties	—				76,780				3,806				354,614
Abandonment and impairment of unproved properties	12,115				74,450				12,272				80,367
Impairment of other property and equipment	—				—				—				—
Stock-based compensation expense	6,540				6,412				22,700				26,897
Net derivative loss	115,778				129,547				26,414				250,633
Derivative settlement gain (loss)	(8,168		)		23,244				21,234				329,478
Amortization of debt discount and deferred financing costs	3,798				4,251				16,276				9,938
(Gain) loss on extinguishment of debt	—				—				35				(15,722		)
Deferred income taxes	(124,608		)		(133,873		)		(192,066		)		(448,643		)
Plugging and abandonment	(640		)		(992		)		(2,735		)		(6,214		)
Other, net	3,526				5,140				8,239				(3,701		)
Changes in current assets and liabilities:
Accounts receivable	(7,505		)		(11,783		)		13,997				(10,562		)
Prepaid expenses and other	7,002				826				(1,953		)		8,478
Accounts payable and accrued expenses	23,425				11,956				44,985				(53,210		)
Accrued derivative settlements	6,538				14,889				12,584				34,540
Net cash provided by operating activities	144,780				137,792				515,390				552,804
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	(1,646		)		744,233				776,719				946,062
Capital expenditures	(263,384		)		(137,117		)		(888,353		)		(629,911		)
Acquisition of proved and unproved oil and gas properties	(2,507		)		(2,161,937		)		(89,896		)		(2,183,790		)
Net cash used in investing activities	(267,537		)		(1,554,821		)		(201,530		)		(1,867,639		)
Cash flows from financing activities:
Proceeds from credit facility	—				204,000				406,000				947,000
Repayment of credit facility	—				(204,000		)		(406,000		)		(1,149,000		)
Debt issuance costs related to credit facility	—				—				—				(3,132		)
Net proceeds from Senior Notes	—				(757		)		—				491,640
Cash paid to repurchase Senior Notes	—				—				(2,344		)		(29,904		)
Cash paid for extinguishment of debt	—				—				(13		)		—
Net proceeds from Senior Convertible Notes	—				(64		)		—				166,617
Cash paid for capped call transactions	—				(86		)		—				(24,195		)
Net proceeds from sale of common stock	885				405,002				2,623				938,268
Dividends paid	(5,581		)		(4,347		)		(11,144		)		(7,751		)
Net share settlement from issuance of stock awards	(1		)		(13		)		(1,240		)		(2,354		)
Other, net	(18		)		—				(171		)		—
Net cash provided by (used in) financing activities	(4,715		)		399,735				(12,289		)		1,327,189
Net change in cash, cash equivalents, and restricted cash	(127,472		)		(1,017,294		)		301,571				12,354
Cash, cash equivalents, and restricted cash at beginning of period	441,415				1,029,666				12,372				18
Cash, cash equivalents, and restricted cash at end of period	$	313,943			$	12,372			$	313,943			$	12,372

14

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Adjusted EBITDAX (1)
(in thousands)
Reconciliation of net loss (GAAP) to adjusted EBITDAX (non-GAAP) to net cash provided by operating activities (GAAP):	For the Three Months								For the Twelve Months
	Ended December 31,								Ended December 31,
	2017				2016				2017				2016
Net loss (GAAP)	$	(26,258	)		$	(200,946	)		$	(160,843	)		$	(757,744	)
Interest expense	43,618				46,356				179,257				158,685
Interest income	(1,067		)		(130		)		(3,968		)		(362		)
Income tax benefit	(117,145		)		(129,667		)		(182,970		)		(444,172		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	131,393				171,552				557,036				790,745
Exploration (2)	14,484				22,289				49,879				59,194
Impairment of proved properties	—				76,780				3,806				354,614
Abandonment and impairment of unproved properties	12,115				74,450				12,272				80,367
Stock-based compensation expense	6,540				6,412				22,700				26,897
Net derivative loss	115,778				129,547				26,414				250,633
Derivative settlement gain (loss)	(8,168		)		23,244				21,234				329,478
Net (gain) loss on divestiture activity	(537		)		(33,661		)		131,028				(37,074		)
(Gain) loss on extinguishment of debt	—				—				35				(15,722		)
Other, net	3,200				(7		)		8,820				(4,764		)
Adjusted EBITDAX (Non-GAAP)	$	173,953			$	186,219			$	664,700			$	790,775
Interest expense	(43,618		)		(46,356		)		(179,257		)		(158,685		)
Interest income	1,067				130				3,968				362
Income tax benefit	117,145				129,667				182,970				444,172
Exploration (2)	(14,484		)		(22,289		)		(49,879		)		(59,194		)
Exploratory dry hole expense	2,381				—				2,381				(16		)
Amortization of debt discount and deferred financing costs	3,798				4,251				16,276				9,938
Deferred income taxes	(124,608		)		(133,873		)		(192,066		)		(448,643		)
Plugging and abandonment	(640		)		(992		)		(2,735		)		(6,214		)
Other, net	326				5,147				(581		)		1,063
Changes in current assets and liabilities	29,460				15,888				69,613				(20,754		)
Net cash provided by operating activities (GAAP)	$	144,780			$	137,792			$	515,390			$	552,804
(1) 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.
(2) 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 accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Adjusted Net Loss	For the Three Months								For the Twelve Months
(in thousands, except per share data)	Ended December 31,								Ended December 31,
	2017				2016				2017				2016
Net loss (GAAP)	$	(26,258	)		$	(200,946	)		$	(160,843	)		$	(757,744	)
Net derivative loss	115,778				129,547				26,414				250,633
Derivative settlement gain (loss)	(8,168		)		23,244				21,234				329,478
Net (gain) loss on divestiture activity	(537		)		(33,661		)		131,028				(37,074		)
Impairment of proved properties	—				76,780				3,806				354,614
Abandonment and impairment of unproved properties	12,115				74,450				12,272				80,367
Termination fee on temporary second lien facility	—				—				—				10,000
(Gain) loss on extinguishment of debt	—				—				35				(15,722		)
Other, net(1)	8,200				(306		)		13,820				(7,731		)
Tax effect of adjustments(2)	(45,987		)		(97,760		)		(75,308		)		(349,173		)
US tax reform(3)	(63,675		)		—				(63,675		)		—
Adjusted net loss (Non-GAAP)(4)	$	(8,532	)		$	(28,652	)		$	(91,217	)		$	(142,352	)
Diluted net loss per common share (GAAP)	$	(0.24	)		$	(2.20	)		$	(1.44	)		$	(9.90	)
Net derivative loss	1.04				1.42				0.24				3.27
Derivative settlement gain (loss)	(0.07		)		0.25				0.19				4.30
Net gain (loss) on divestiture activity	—				(0.37		)		1.18				(0.48		)
Impairment of proved properties	—				0.84				0.03				4.63
Abandonment and impairment of unproved properties	0.11				0.81				0.11				1.05
Termination fee on temporary second lien facility	—				—				—				0.13
(Gain) loss on extinguishment of debt	—				—				—				(0.21		)
Other, net(1)	0.07				(0.01		)		0.12				(0.10		)
Tax effect of adjustments(2)	(0.42		)		(1.05		)		(0.68		)		(4.55		)
US tax reform(3)	(0.57		)		—				(0.57		)		—
Adjusted net loss per diluted common share (Non-GAAP)(4)	$	(0.08	)		$	(0.31	)		$	(0.82	)		$	(1.86	)
Diluted weighted-average shares outstanding (GAAP)	111,611				91,440				111,428				76,568
(1) For the three-month and twelve-month periods ended December 31, 2017, the adjustment is related to impairment on materials inventory, pension settlement expense, the change in Net Profits Plan liability, bad debt expense, and an accrual for a non-recurring matter. For the three-month and twelve-month periods ended December 31, 2016, the adjustment relates to the change in Net Profits Plan liability, impairment of materials inventory, and an adjustment relating to claims on royalties on certain Federal and Indian leases. Pension settlement expense is included within exploration expenses and general and administrative expense on the Company's consolidated statements of operations. Other noted items are included in other operating expenses on the Company's consolidated statements of operations.
(2) For the three and twelve-month periods ended December 31, 2017, adjustments are shown before tax effect which is calculated using a tax rate of 36.1%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. For the three and twelve-month periods ended December 31, 2016, adjustments are shown before tax effect and are calculated using a tax rate of 36.2%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences.
(3) US tax reform adjustment primarily relates to the enactment of the 2017 Tax Act on December 22, 2017, which reduced the Company's federal tax rate for 2018 and future years from 35 percent to 21 percent.
(4) Adjusted net 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, 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.

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Regional proved oil and gas reserve quantities:
		Permian			Eagle Ford(1)			Rocky Mountain			Total
Year-end 2017 proved reserves
Oil (MMBbl)		117.5			13.3			27.4			158.2
Gas (Bcf)		252.8			998.1			29.2			1,280.1
NGL (MMBbl)		0.2			95.6			0.7			96.5
Total (MMBOE)		159.9			275.2			33.0			468.1
% Proved developed		34	%		52	%		53	%		46	%
Note: Totals may not sum due to rounding
(1) Includes nominal amounts outside of the Eagle Ford.

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Total Capital Spend Reconciliation:
(in millions)
Reconciliation of costs incurred in oil & gas activities (GAAP) to total capital spend (Non-GAAP)(1)(3)	For the Year Ended December 31, 2017
Costs incurred in oil and gas activities (GAAP):	$	1,040.0
Asset retirement obligations	(12.1		)
Capitalized interest	(12.6		)
Proved property acquisitions(2)	(1.6		)
Unproved property acquisitions	(78.6		)
Other	1.3
Total capital spend (Non-GAAP):	$	936.4
(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 $1.4 million of ARO associated with proved property acquisitions for the year ended December 31, 2017.
(3) The Company completed several primarily non-monetary acreage trades in the Midland Basin during 2017 totaling $294.0 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.

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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
PV-10 Reconciliation:
(in millions)
Reconciliation of standardized measure (GAAP) to PV-10 (Non-GAAP)(1)	As of December 31, 2017
Standardized measure of discounted future net cash flows (GAAP):	$	3,024.1
Add: 10 percent annual discount, net of income taxes	2,573.2
Add: future undiscounted income taxes	205.7
Undiscounted future net cash flows	5,803.0
Less: 10 percent annual discount without tax effect	(2,746.5		)
PV-10 (Non-GAAP):	$	3,056.5
(1) The non-GAAP measure of PV-10 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 PV-10 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. PV-10 should not be considered in isolation or as a substitute for other measures prepared under GAAP.

19