Exhibit

Exhibit 99.1

FOR IMMEDIATE RELEASE

SM ENERGY REPORTS 2015 RESULTS AND 2016 OPERATING PLAN:

MAINTAINING BALANCE SHEET STRENGTH

WHILE INCREASING ACTIVITY IN THE PERMIAN

Denver, Colorado February 23, 2016 - SM Energy Company ("SM Energy" or the “Company”) (NYSE: SM) announces today fourth quarter and full year 2015 financial and operating results, year-end 2015 reserves and the Company’s 2016 operating plan. Highlights include:


•	Proved reserves: 471 MMBoe at year-end 2015, including +208 MMBoe additions and revisions driven by well performance and successful resource expansion in the Eagle Ford and Bakken/Three Forks


•	2016 operating strategy: preserve the Company's strong balance sheet and liquidity by optimizing capital efficiency; plan delivers projected total debt:adjusted EBITDAX of less than 4 times through 2017


•	2015 financial results: adjusted net loss of $35.9 million, or $0.53 per diluted common share, and adjusted EBITDAX of $1,125 million (see GAAP reconciliation below)


•	Previously reported 2015 results: record production of 64.2 MMBoe and year-end liquidity of $1.3 billion with debt:adjusted EBITDAX of 2.3 times

President and Chief Executive Officer Jay Ottoson comments: “In 2015, we delivered record production with a capital program cut in half from 2014. We aggressively applied new drilling and completion techniques and tested expansions of our core programs that added more than 200 MMBoe of proved reserves, delivered significant growth in inventory, and furthered the upside potential of core assets.

“Our 2016 plan includes capital expenditures of approximately $705 million, a more than 45% cut from 2015. While a portion of our capital will be spent in the Eagle Ford in order to hold acreage, we will be completing a number of drilled and uncompleted wells in both the Eagle Ford and Bakken/Three Forks, and to the maximum extent possible we will be shifting our drilling and completion activity to our highly productive Midland Basin shale development. We will focus on continuing to improve the performance and economics of our portfolio and position the Company for significant value growth as product prices recover."

2016 OPERATING PLAN AND GUIDANCE

SM Energy's operating plan demonstrates the quality and optionality of the Company's asset base. Key assumptions in the Company's 2016 operating plan include:


•	Total capital before acquisitions of approximately $705 million, weighted to 1H16


•	Williston - drill approximately 20 wells and complete approximately 50 wells (gross)


•	Permian - drill approximately 20 wells and complete approximately 24 wells (gross)


•	Eagle Ford - drill approximately 15 wells and complete approximately 40 (gross, operated)


•	Divest several non-core PDP assets by year-end for expected proceeds of at least $100 million


•	Average commodity price projections: 2016 - WTI oil $37.50, Henry Hub natural gas $2.30, NGLs $15.50; 2017 - WTI oil $45.00, Henry Hub natural gas $2.75, NGLs $18.00

The 2016 capital program is designed to optimize cash flow while keeping total expenditures below projected EBITDAX. The program is expected to result in total production for 2016 of 51-55 MMBoe. Production guidance reflects planned divestitures and reduced activity in dry natural gas programs, as well as a projected increase in the percentage of oil in the production mix in the second half of the year due to production growth from the Permian and Williston basins. Given the Company's commodity price assumptions, and additional cost guidance below, the Company projects debt:adjusted EBITDAX at year-end 2016 of approximately 3.5 times and year-end 2017 of less than 4.0 times. The Company has 2016 hedges in place for: more than 30% of projected oil production at an average price of $88.01/Bbl WTI; more than 55% of projected natural gas production at an average price of $3.61/MMBtu; and approximately 60% of projected NGL production, specifically ethane and propane. Assuming similar production in 2017, the Company has hedges in place for more than 50% of natural gas production at $4.26 per MMBtu.

2016 Guidance:

Capital ~ $705 million, before acquisitions

Production 51-55 MMBoe

LOE $4.10-$4.50 per Boe, including ad valorem taxes

Transportation $6.10-$6.30 per Boe

Production taxes ~$1.00 per Boe or 5%

G&A $130-136 million,

including approximately $21-23 million non-cash compensation

Exploration $62-66 million, before dry hole expense,

all of which is included in capital expenditure guidance

DD&A $15.50-17.50 per Boe

The Company expects first quarter of 2016 production of approximately 13.1-13.5 MMBoe. Lower sequential production from the fourth quarter of 2015 is primarily the result of the Company's plan to reduce activity in the Eagle Ford, where activity was slowed early in the fourth quarter of 2015, and increase activity in the Permian, where drilling was restarted in January. The transition from natural gas to oil results in lower volumes yet higher cash margins.

2015 FINANCIAL AND OPERATING RESULTS

PROVED RESERVES

Year-end 2015 proved reserves of 471 MMBoe are calculated in accordance with SEC pricing at $50.28 per barrel of oil NYMEX, $2.59 per MMBtu of natural gas at Henry Hub and $20.20 per barrel of NGLs at Mt. Belvieu. Year-end proved reserves were 55% liquids ( 31% oil and 24% NGLs) and 45% natural gas. 52% were proved developed.

During 2015, the Company added 161 MMBoe of reserves, predominantly in its operated Eagle Ford and Bakken/Three Forks program in Divide County, North Dakota. These reserve additions are a result of high-grading inventory through improved completion designs, better targeting of landing intervals, further delineation of the Bakken formation and further delineation of acreage acquired in late 2014 in both the Bakken and Three Forks intervals. The Company also added 47 MMBoe of proved reserves based on performance revisions, reflecting improved well performance in the Eagle Ford and Bakken/Three Forks programs primarily as a result of completion design enhancements, such as increased sand loading and plug-n-perf design, as well as reductions in operating costs. As a result of improved well performance and higher quality drilling locations, the Company revised its five-year plan to high-grade certain drilling in both the Eagle Ford and Bakken/Three Forks programs, which postponed the drilling of certain previously proved locations beyond five years. This resulted in moving 79 MMBoe of proved reserves predominantly to the probable category, to conform with SEC five-year rule; in effect, recent pilots and testing programs enabled reserve additions in our new development plans and deferred proved reserves from previous development plans beyond the 5-year development horizon. In addition, proved reserves

were reduced by 117 MMBoe as a direct result of lower SEC pricing at year-end 2015. The table below provides a reconciliation of changes in the Company’s proved reserves from year-end 2014 to year-end 2015 (numbers are rounded):

Proved reserves year-end 2014 (adjusted for asset sales) 522 MMBoe

Production (adjusted for assets sold) (63)

Reserve additions through drilling 161

Reserve additions through performance revisions 47

Reserve revisions to high-grade 5-year plan/5-year rule (79)

Reserve revisions due to commodity price changes (117)

Year-end 2015 proved reserves 471 MMBoe

Production replacement (reserve additions and performance revisions/2015 total production) was 324%, making six years sequentially when this metric exceeded 250%. The cost to add reserves was $6.35 per Boe calculated as total capital expenditures/reserve additions and performance revisions, before price and proved undeveloped reserve vintage revisions (see below for reconciliation of total capital spend to costs incurred.)

The pre-tax present value of proved reserves discounted at 10%, or PV-10, (see GAAP reconciliation below) was $1.8 billion. PV-10 is calculated using the SEC pricing described above. Including the present value of the Company’s oil, natural gas and NGL hedge positions, PV-10 is estimated at $2.3 billion.

CAPITAL EXPENDITURES

Full year 2015 total capital spend (see below for GAAP reconciliation) was $1.3 billion and was allocated 52% to the Eagle Ford, 28% to the Bakken/Three Forks and 20% to the Permian Basin, Powder River Basin and other. Total capital spend included development capital of $1,148 million, $17 million for leasehold, $70 million for infrastructure and $79 million for corporate costs. During 2015, the Company drilled 236 net wells and completed 161 net wells.

FINANCIAL RESULTS

Adjusted EBITDAX and adjusted net income are non-GAAP measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

Adjusted EBITDAX was $216 million for the fourth quarter of 2015 and $1,125 million for the full year 2015. Adjusted EBITDAX declined 32% in 2015 compared with 2014, primarily as a result of a 48% decline in commodity prices, partially offset by a 16% increase in total production, a 14% decline in cash operating costs per Boe, a 19% decline in general and administrative costs per Boe and higher commodity hedge settlements.

Net loss was $340.3 million, or $5.01 per diluted common share, for the fourth quarter of 2015 and $447.7 million, or $6.61 per diluted common share, for the full year. The Company recorded impairments and abandonment charges on proved and unproved properties and equipment of $448.2 million ($284.6 million after-tax) and $596.7 million ($378.9 million after-tax) for the fourth quarter and full year, respectively. The net loss for 2015 compares with net income of $666.1 million, or $9.79 per diluted common share, in 2014. Lower net income is primarily a result of lower cash margins before derivative settlements described above due to the decline in commodity prices, a 3% increase in per unit depletion, depreciation and amortization and increased impairment charges recorded in 2015.

Adjusted net loss was $61.1 million, or $0.90 per diluted common share, for the fourth quarter of 2015 and $35.9 million, $0.53 per diluted common share, for the full year.

OPERATIONS UPDATE

Optimizing expenditures and driving efficiencies were key goals of the 2015 operating plan. Company-wide drilling costs declined 30%-40% from mid-2014, including drilling rig rate reductions and drilling

times that improved 5%-15%, while completion costs dropped as much as 50%, including larger fracture stimulations, reflecting both service provider cost reductions and efficiency gains. The 2015 operating plan slowed activity in the second half of 2015, particularly in the fourth quarter. The Company reduced drilling activity to six operated rigs by year-end, postponed gas well completions in the Eagle Ford starting in October, postponed all completions in the Eagle Ford after November and slowed the pace of well completions in Bakken/Three Forks, while third party-operated Eagle Ford activity was also significantly reduced.

This change in activity supported the planned transition from natural gas and condensate development in the operated Eagle Ford to oil-focused activity in the Permian and Williston basins. The Company currently has 4 operated rigs and 3 completions crews.

Eagle Ford

During the fourth quarter of 2015, the Company drilled 29 net wells and completed 20 net wells (operated and third party-operated), ending the year with a DUC inventory of 76 net operated wells and 40 net third party-operated wells. The Company currently is operating 1 rig in the Eagle Ford East area.

The Company continues to evaluate stack and stagger down-spacing pilot test results in the Eagle Ford. Pilot Tests #1 through #5 are currently flowing back and some pilot wells are awaiting artificial lift installation. The Company plans to defer tests #6 and #9 as part of the 2016 re-allocation of capital to the Permian Basin.

Bakken/Three Forks

During the fourth quarter of 2015, the Company drilled 13 net wells and completed 11 net wells, ending the year with a DUC inventory of 40 net wells. The Company currently is operating 2 rigs in Divide County, North Dakota.

Permian Basin

The Company re-initiated drilling activity on its Sweetie Peck asset in early January 2016. The Company currently is operating 1 rig and expects to redeploy a second rig from the Eagle Ford to the Permian later in the year. The 2016 drilling program targets the Wolfcamp B and Lower Spraberry intervals. The Sweetie Peck play is located in a prime position in Upton and Midland counties and includes approximately 15,200 net contiguous acres.

UPCOMING EVENTS

EARNINGS WEBCAST AND CALL

As previously announced, SM Energy will host a webcast and conference call to discuss the 2015 results and the 2016 operating plan at 8:00 a.m. Mountain time tomorrow, February 24, 2016. Please join us via webcast at www.SM-Energy.com or by telephone 877-303-1292 (toll free) or 315-625-3086 (international) with passcode 46889560. The webcast and call will also be available for replay. The dial-in replay number is 855-859-2056 (toll free) or 404-537-3406 (international) with passcode 46889560 and is available through March 9, 2016.

A presentation will be posted to the Company’s website to accompany this call at www.SM-Energy.com

UPCOMING CONFERENCE PARTICIPATION


•	February 25, 2016 - 21^st Annual Credit Suisse Energy Summit. Executive Vice President and Chief Financial Officer Wade Pursell will present at 7:25 a.m. Mountain time. This event will be webcast.


•	March 3, 2016 - Simmons Sixteenth Annual Energy Conference. President and Chief Executive Officer Jay Ottoson will meet with investors in a 1x1 setting.


•	March 9, 2016 - Raymond James 37^th Annual Institutional Investors Conference. Executive Vice President and Chief Financial Officer Wade Pursell will present at 11:35 a.m. Eastern time. This event will be webcast.

The investor presentation for these events will be posted to the Company’s website at www.SM-Energy.com on February 24, 2016 after market close.

FORWARD LOOKING STATEMENTS

This release contains forward-looking statements within the meaning of securities laws, including forecasts, projections and 2016 guidance. The words “guidance,” “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” "going forward," “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 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 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 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 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 2015 Annual Report on Form 10-K upon filing, 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.

INFORMATION ABOUT PROVED RESERVES

This press release contains references to certain items pertaining to the process used to estimate the Company's proved reserves and their PV-10, which is equal to the standardized measure of discounted future net cash flows from proved reserves on the applicable date, before deducting future income taxes, discounted at 10 percent. SM Energy believes that the presentation of pre-tax PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's proved reserves prior to taking into account future corporate income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 as a basis for comparison of the relative size and value of the Company's proved reserves to other peer companies. SM Energy's pre-tax PV-10 for estimated proved reserves as of December 31, 2015, may be reconciled to its standardized measure of discounted future net cash flows as of December 31, 2015, by reducing the Company's pre-tax PV-10 by the discounted future income taxes associated with such reserves. A reconciliation of these adjustments is provided below.

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 Samuels, ir@sm-energy.com, 303-863-2507

MEDIA:

Patty Errico, perrico@sm-energy.com, 303-830-5052



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2015

	For the Three Months Ended December 31,						For the Twelve Months Ended December 31,
Production Data:	2015		2014		Percent Change		2015		2014		Percent Change

Average realized sales price, before the
effects of derivative settlements:
Oil (per Bbl)	$	34.93	$	62.60	(44	)%	$	41.49	$	80.97	(49	)%
Gas (per Mcf)	2.19		3.87		(43	)%	2.57		4.58		(44	)%
NGL (per Bbl)	14.99		25.97		(42	)%	15.92		33.34		(52	)%
Equivalent (per BOE)	$	20.03	$	36.27	(45	)%	$	23.36	$	45.01	(48	)%

Average realized sales price, including
the effects of derivative settlements:
Oil (per Bbl)	$	55.81	$	73.55	(24	)%	$	60.34	$	82.68	(27	)%
Gas (per Mcf)	2.96		3.91		(24	)%	3.28		4.40		(25	)%
NGL (per Bbl)	15.60		30.71		(49	)%	17.61		34.18		(48	)%
Equivalent (BOE)	$	28.40	$	40.94	(31	)%	$	31.34	$	45.23	(31	)%

Production:
Oil (MMBbls)	4.4		5.1		(14	)%	19.2		16.7		15	%
Gas (Bcf)	40.2		43.9		(8	)%	173.6		152.9		14	%
NGL (MMBbls)	3.8		3.8		2	%	16.1		13.0		24	%
MMBOE (6:1)	14.9		16.2		(8	)%	64.2		55.1		16	%

Average daily production:
Oil (MBbls/d)	47.7		55.4		(14	)%	52.7		45.6		15	%
Gas (MMcf/d)	436.6		476.9		(8	)%	475.7		419.0		14	%
NGL (MBbls/d)	41.6		40.9		2	%	44.0		35.6		24	%
MBOE/d (6:1)	162.1		175.8		(8	)%	175.9		151.1		16	%

Per BOE Data:
Realized price before the effects of derivative settlements	$	20.03	$	36.27	(45	)%	$	23.36	$	45.01	(48	)%
Lease operating expense	3.85		4.28		(10	)%	3.73		4.28		(13	)%
Transportation costs	6.10		5.77		6	%	6.02		6.11		(1	)%
Production taxes	1.03		1.70		(39	)%	1.13		2.13		(47	)%
Ad valorem tax expense	0.38		0.38		—	%	0.39		0.46		(15	)%
General and administrative	2.26		3.23		(30	)%	2.46		3.03		(19	)%
Operating profit, before the effects of derivative settlements	$	6.41	$	20.91	(69	)%	$	9.63	$	29.00	(67	)%
Derivative settlement gain	8.37		4.67		79	%	7.98		0.22		3,527	%
Operating profit, including the effects of derivative settlements	$	14.78	$	25.58	(42	)%	$	17.61	$	29.22	(40	)%

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	16.10	$	13.56	19	%	$	14.34	$	13.92	3	%



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
December 31, 2015

Consolidated Statements of Operations
(in thousands, except share amounts)	For the Three Months Ended December 31,						For the Twelve Months Ended December 31,
	2015			2014			2015			2014
Operating revenues:
Oil, gas, and NGL production revenue	$	298,719		$	586,567		$	1,499,905		$	2,481,544
Net gain on divestiture activity	4,534			594			43,031			646
Marketed gas system revenue	4			7,200			9,485			24,897
Other operating revenues	477			1,460			4,544			15,220
Total operating revenues and other income	303,734			595,821			1,556,965			2,522,307

Operating expenses:
Oil, gas, and NGL production expense	169,229			196,181			723,633			715,878
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	240,025			219,277			921,009			767,532
Exploration	37,942			49,696			120,569			129,857
Impairment of proved properties	344,249			84,480			468,679			84,480
Abandonment and impairment of unproved properties	54,597			57,151			78,643			75,638
Impairment of other property and equipment	49,369			—			49,369			—
General and administrative	33,642			52,241			157,668			167,103
Change in Net Profits Plan liability	(6,351		)	(14,569		)	(19,525		)	(29,849		)
Derivative gain	(123,340		)	(616,734		)	(408,831		)	(583,264		)
Marketed gas system expense	(7		)	6,759			13,922			24,460
Other operating expenses	9,952			2,854			30,612			4,658
Total operating expenses	809,307			37,336			2,135,748			1,356,493

Income (loss) from operations	(505,573		)	558,485			(578,783		)	1,165,814

Non-operating income (expense):
Other, net	26			(68		)	649			(2,561		)
Interest expense	(31,566		)	(27,703		)	(128,149		)	(98,554		)
Loss on extinguishment of debt	—			—			(16,578		)	—

Income (loss) before income taxes	(537,113		)	530,714			(722,861		)	1,064,699
Income tax (expense) benefit	196,855			(198,988		)	275,151			(398,648		)

Net income (loss)	$	(340,258	)	$	331,726		$	(447,710	)	$	666,051

Basic weighted-average common shares outstanding	67,976			67,410			67,723			67,230

Diluted weighted-average common shares outstanding	67,976			67,535			67,723			68,044

Basic net income (loss) per common share	$	(5.01	)	$	4.92		$	(6.61	)	$	9.91

Diluted net income (loss) per common share	$	(5.01	)	$	4.91		$	(6.61	)	$	9.79



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
December 31, 2015
Consolidated Balance Sheets
(in thousands, except share amounts)	December 31,			December 31,
ASSETS	2015			2014

Current assets:
Cash and cash equivalents	$	18		$	120
Accounts receivable	134,124			322,630
Derivative asset	367,710			402,668
Prepaid expenses and other	17,137			19,625
Total current assets	518,989			745,043

Property and equipment (successful efforts method):
Proved oil and gas properties	7,606,405			7,348,436
Less - accumulated depletion, depreciation, and amortization	(3,481,836		)	(3,233,012		)
Unproved oil and gas properties	284,538			532,498
Wells in progress	387,432			503,734
Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $0 and $22,482, respectively	641			17,891
Other property and equipment, net of accumulated depreciation of $32,956 and $37,079, respectively	153,100			334,356
Total property and equipment, net	4,950,280			5,503,903

Noncurrent assets:
Derivative asset	120,701			189,540
Other noncurrent assets	31,673			44,659
Total other noncurrent assets	152,374			234,199

Total Assets	$	5,621,643		$	6,483,145

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	302,517		$	640,684
Derivative liability	8			—
Deferred tax liability	—			142,976
Other current liabilities	—			1,000
Total current liabilities	302,525			784,660

Noncurrent liabilities:
Revolving credit facility	202,000			166,000
Senior Notes, net of unamortized deferred financing costs	2,315,970			2,166,445
Asset retirement obligation	137,525			120,867
Net Profits Plan liability	7,611			27,136
Deferred income taxes	758,279			891,681
Derivative liability	—			70
Other noncurrent liabilities	45,332			39,631
Total noncurrent liabilities	3,466,717			3,411,830

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 68,075,700 and 67,463,060 shares, respectively	681			675
Additional paid-in capital	305,607			283,295
Retained earnings	1,559,515			2,013,997
Accumulated other comprehensive loss	(13,402		)	(11,312		)
Total stockholders’ equity	1,852,401			2,286,655

Total Liabilities and Stockholders’ Equity	$	5,621,643		$	6,483,145



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
December 31, 2015

Consolidated Statements of Cash Flows
(in thousands)	For the Three Months						For the Twelve Months
	Ended December 31,						Ended December 31,
	2015			2014			2015			2014
Cash flows from operating activities:
Net income (loss)	$	(340,258	)	$	331,726		$	(447,710	)	$	666,051
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain on divestiture activity	(4,534		)	(594		)	(43,031		)	(646		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	240,025			219,277			921,009			767,532
Exploratory dry hole expense	13,752			21,583			36,612			44,427
Impairment of proved properties	344,249			84,480			468,679			84,480
Abandonment and impairment of unproved properties	54,597			57,151			78,643			75,638
Impairment of other property and equipment	49,369			—			49,369			—
Stock-based compensation expense	6,975			8,126			27,467			32,694
Change in Net Profits Plan liability	(6,351		)	(14,569		)	(19,525		)	(29,849		)
Derivative gain	(123,340		)	(616,734		)	(408,831		)	(583,264		)
Derivative settlement gain	124,847			75,509			512,566			12,615
Amortization of deferred financing costs	1,907			1,713			7,710			6,146
Non-cash loss on extinguishment of debt	—			—			4,123			—
Deferred income taxes	(196,334		)	199,600			(276,722		)	397,780
Plugging and abandonment	(1,956		)	(2,603		)	(7,496		)	(8,796		)
Other, net	10,091			4,003			13,761			1,069
Changes in current assets and liabilities:
Accounts receivable	34,864			14,705			140,200			24,088
Prepaid expenses and other	1,976			(2,056		)	2,563			(1,822		)
Accounts payable and accrued expenses	(12,020		)	36,270			(86,267		)	9,466
Accrued derivative settlements	(4,356		)	(36,134		)	5,232			(41,034		)
Net cash provided by operating activities	193,503			381,453			978,352			1,456,575

Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	22,835			1,990			357,938			43,858
Capital expenditures	(231,737		)	(656,936		)	(1,493,608		)	(1,974,798		)
Acquisition of proved and unproved oil and gas properties	(896		)	(85,276		)	(7,984		)	(544,553		)
Other, net	5			(2,542		)	(985		)	(3,256		)
Net cash used in investing activities	(209,793		)	(742,764		)	(1,144,639		)	(2,478,749		)

Cash flows from financing activities:
Proceeds from credit facility	268,000			749,000			1,872,500			1,285,500
Repayment of credit facility	(250,000		)	(973,000		)	(1,836,500		)	(1,119,500		)
Debt issuance costs related to credit facility	—			(3,388		)	—			(3,388		)
Net proceeds from Senior Notes	—			589,991			490,951			589,991
Repayment of Senior Notes	—			—			(350,000		)	—
Proceeds from sale of common stock	1,687			1,979			4,844			4,877
Dividends paid	(3,399		)	(3,370		)	(6,772		)	(6,723		)
Net share settlement from issuance of stock awards	(176		)	(48		)	(8,678		)	(10,624		)
Other, net	(1		)	(2		)	(160		)	(87		)
Net cash provided by financing activities	16,111			361,162			166,185			740,046

Net change in cash and cash equivalents	(179		)	(149		)	(102		)	(282,128		)
Cash and cash equivalents at beginning of period	197			269			120			282,248
Cash and cash equivalents at end of period	$	18		$	120		$	18		$	120



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2015

Adjusted Net Income (Loss)
(in thousands, except per share data)

Reconciliation of net income (loss) (GAAP)	For the Three Months						For the Twelve Months
to adjusted net income (loss) (Non-GAAP):	Ended December 31,						Ended December 31,
	2015			2014			2015			2014

Actual net income (loss) (GAAP)	(340,258		)	$	331,726		$	(447,710	)	$	666,051

Adjustments net of tax: ⁽¹⁾
Change in Net Profits Plan liability	(4,033		)	(9,164		)	(12,398		)	(18,775		)
Derivative gain	(78,321		)	(387,926		)	(259,608		)	(366,873		)
Derivative settlement gain	79,278			47,495			325,479			7,935
Net gain on divestiture activity	(2,879		)	(374		)	(27,325		)	(406		)
Impairment of proved properties	218,598			53,138			297,611			53,138
Abandonment and impairment of unproved properties	34,669			35,948			49,938			47,576
Impairment of other property and equipment	31,349			—			31,349			—
Loss on extinguishment of debt	—			—			10,527			—
Unwinding of derivatives contracts related to Mid-continent	—			—			(9,734		)	(3,536		)
Other ⁽³⁾	540			68			5,963			(5,032		)

Adjusted net income (loss) (Non-GAAP) ⁽²⁾	$	(61,057	)	$	70,911		$	(35,908	)	$	380,078

Adjusted net income (loss) per diluted common share	$	(0.90	)	$	1.05		$	(0.53	)	$	5.59

Diluted weighted-average shares outstanding	67,976			67,535			67,723			68,044


(1) For the three and twelve-month periods ended December 31, 2015, adjustments are shown net of tax and are calculated using a tax rate of 36.5%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. For the three and twelve-month periods ended December 31, 2014, adjustments are shown net of tax and are calculated using a tax rate of 37.1%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences.
(2) Adjusted net income (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 the change in the Net Profits Plan liability, derivative gain, net of derivative settlement gains, impairments, and net gain on divestiture activity. 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.
(3) For the three and twelve-month periods ended December 31, 2015, the adjustment is related to the impairment of materials inventory and an estimated adjustment relating to claims on royalties on certain Federal and Indian leases, which are included in other operating expenses on the Company's condensed consolidated statements of operations. For the three and twelve-month periods ended December 31, 2014, adjustments include items related to settlements from the previously disclosed litigation against Endeavour Operating Corporation. These items are included as a portion of other operating revenues and non-operating income (expense), other, net, on the Company's consolidated statement of operations.



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2015

Adjusted EBITDAX ⁽⁴⁾
(in thousands)

Reconciliation of net income (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,
	2015			2014			2015			2014
Net income (loss) (GAAP)	$	(340,258	)	$	331,726		$	(447,710	)	$	666,051
Interest expense	31,566			27,703			128,149			98,554
Other non-operating (income) expense, net	(26		)	68			(649		)	2,561
Income tax expense (benefit)	(196,855		)	198,988			(275,151		)	398,648
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	240,025			219,277			921,009			767,532
Exploration ⁽⁵⁾	35,860			47,881			113,158			122,577
Impairment of proved properties	344,249			84,480			468,679			84,480
Abandonment and impairment of unproved properties	54,597			57,151			78,643			75,638
Impairment of other property and equipment	49,369			—			49,369			—
Stock-based compensation expense	6,975			8,126			27,467			32,694
Derivative gain	(123,340		)	(616,734		)	(408,831		)	(583,264		)
Derivative settlement gain ⁽⁶⁾	124,847			75,509			512,566			12,615
Change in Net Profits Plan liability	(6,351		)	(14,569		)	(19,525		)	(29,849		)
Net gain on divestiture activity	(4,534		)	(594		)	(43,031		)	(646		)
Loss on extinguishment of debt	—			—			16,578			—
Other, net	153			—			4,054			—
Adjusted EBITDAX (Non-GAAP)	$	216,277		$	419,012		$	1,124,775		$	1,647,591
Interest expense	(31,566		)	(27,703		)	(128,149		)	(98,554		)
Other non-operating income (expense), net	26			(68		)	649			(2,561		)
Income tax (expense) benefit	196,855			(198,988		)	275,151			(398,648		)
Exploration ⁽⁵⁾	(35,860		)	(47,881		)	(113,158		)	(122,577		)
Exploratory dry hole expense	13,752			21,583			36,612			44,427
Amortization of deferred financing costs	1,907			1,713			7,710			6,146
Deferred income taxes	(196,334		)	199,600			(276,722		)	397,780
Plugging and abandonment	(1,956		)	(2,603		)	(7,496		)	(8,796		)
Loss on extinguishment of debt	—			—			(12,455		)	—
Other, net	9,938			4,003			9,707			1,069
Changes in current assets and liabilities	20,464			12,785			61,728			(9,302		)
Net cash provided by operating activities (GAAP)	$	193,503		$	381,453		$	978,352		$	1,456,575

(4) Adjusted EBITDAX represents net income (loss) before interest expense, other non-operating income or expense, income taxes, depreciation, depletion, amortization, and accretion expense, exploration expense, impairments, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, and gains and losses 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 in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes it provides useful additional information to investors and analysts, 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 a financial covenant 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 (loss), income (loss) from operations, net cash provided by operating activities, or 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.

(5) 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.

(6) Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include a $15.3 million gain and $5.6 million gain on the early settlement of futures contracts during the second quarter of 2015 and first quarter of 2014, respectively, as a result of divesting our Mid-Continent assets.




Regional proved oil and gas reserve quantities:

	South Texas & Gulf Coast		Rocky Mountain		Permian		Total
Year-end 2015 proved reserves
Oil (MMBbl)	43.6		88.2		13.4		145.3
Gas (Bcf)	1,116.9		102.9		44.2		1,264.0
NGL (MMBbl)	112.6		2.8		—		115.4
Total (MMBOE)	342.4		108.1		20.8		471.3
% Proved developed	50	%	57	%	49	%	52	%

*Totals may not sum due to rounding.



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2015

Costs incurred in oil and gas producing activities⁽¹⁾:
(in thousands)
Reconciliation of Cost Incurred in Oil and Gas Producing Activities (GAAP) to Total Capital Spend (Non-GAAP)	For the Year Ended December 31, 2015

Development costs ⁽²⁾	$	1,234,114
Exploration costs	132,465
Acquisition costs:
Proved properties	10,040
Unproved properties	18,382
Total, including asset retirement obligation	$	1,395,001

Less: Asset retirement obligation	(38,506		)
Less: Capitalized interest	(25,051		)
Less: Proved property acquisitions	(10,040		)
Less: Other	(7,388		)
Total Capital Spend	$	1,314,016

(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 Cost 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 facility costs of $75.6 million.



Reconciliation of standardized measure (GAAP) to PV-10 (Non-GAAP):

	As of December 31,
	2015
	(in millions)
Standardized measure of discounted future net cash flows (GAAP)	$	1,868.9
Add: 10 percent annual discount, net of income taxes	1,228.7
Add: future undiscounted income taxes	—
Undiscounted future net cash flows	3,097.6
Less: 10 percent annual discount without tax effect	(1,307.1		)
PV-10 (Non-GAAP)	$	1,790.5

PV-10 is a commonly used measure that removes the tax effect from the standardized measure of discounted future net cash flows. Management finds this measure to be widely used by investment professionals and believes the presentation of PV-10 is helpful in evaluating and comparing Company data. This measure should not be used in isolation.