Exhibit 99.1 7.28.15

Exhibit 99.1

FOR IMMEDIATE RELEASE

SM ENERGY REPORTS SECOND QUARTER OF 2015 RESULTS -

EXECUTION AND WELL PERFORMANCE DRIVE PRODUCTION AND CASH FLOW


•	Produced 16.5 million barrels of equivalent (MMBOE), up 23% from the prior year period and exceeded plan


•	Realized $337 million adjusted EBITDAX and $0.49 per diluted common share adjusted net income, driven by well performance and lower costs (see GAAP reconciliations below)


•	Encouraged by preliminary results from a 14-well Eagle Ford down-spacing test


•	Demonstrated performance from 9 Bakken test wells in Divide County that are exceeding type curve


•	Maintained 1.7 times debt to adjusted TTM EBITDAX

DENVER, CO July 28, 2015 - SM Energy Company (NYSE: SM) announces its financial results for the second quarter of 2015 and provides an operations update. In conjunction with this release, an updated presentation providing the Company's second quarter earnings and operations is posted on the Company's website at www.sm-energy.com. This presentation will be referenced during the conference call scheduled for 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) on July 29, 2015. Information for the call can be found below.

MANAGEMENT COMMENTARY

Comments from President and Chief Executive Officer Jay Ottoson: "Our Company had an outstanding second quarter. Production came in ahead of budget, primarily as a result of strong well performance in both the Eagle Ford and Williston Basin as completion optimization is driving production performance above our type curves. Further, a number of new wells in our Eagle Ford East area down-spacing test program came into sales during the quarter with strong early production results.

"Unit lease operating costs were significantly below our forecast due to rapid improvements in recently acquired properties in Divide County, North Dakota and generally lower costs across all producing assets. In combination, strong production and lower costs drove very strong EBITDAX for the quarter. The balance sheet was further supported by completion of our Mid-Continent asset sales that generated net proceeds of approximately $317 million. The Company ended the second quarter with $0.12 B drawn on its $2.4 B revolving credit facility and total debt of 1.7 times (trailing twelve month) EBITDAX.

"Capital expenditures in the quarter of $339 million tracked right on budget for the full year for operated interests as the Company stepped down activity from 17 rigs at the start of the year to nine rigs at the end of the second quarter. Total capital is approximately $50 million above our original budget due to partner non-consents and higher than projected partner operated costs in the first half of 2015. We anticipate significantly lower capital spending in the second half of

2015 of approximately $460 million for the six month period as we further reduce the rig count to seven and benefit from realized declines in drilling and completion costs.

"Looking forward through 2015, we have raised the mid-point of production guidance and significantly lowered lease operating expense guidance. We expect to prove-up additional inventory in our Eagle Ford and Williston Basin play areas while ending the year without accumulating additional debt. During 2016, we believe that our current portfolio can deliver production growth over 2015 (exit rate over exit rate) while investing within EBITDAX. We are pleased with our 2015 results to date and believe that our Company will be very well positioned going into 2016.”

SECOND QUARTER 2015 RESULTS

Production for the second quarter of 2015 was 16.5 MMBOE, or 181 MBOE/d, up 23% compared with 13.4 MMBOE, or 147 MBOE/d, in the second quarter of 2014. Production exceeded quarterly guidance by approximately 0.5 MMBOE as a result of better than expected performance from key programs. The slight sequential decline in production from 16.8 MMBOE in the first quarter of 2015 was primarily due to planned third party maintenance in the Eagle Ford, which was completed on schedule. Company-wide production mix for the quarter was 31% oil, 45% natural gas and 24% natural gas liquids ("NGLs"). Production from Mid-Continent assets sold during the quarter totaled 677 MBOE ( 96% natural gas). For the first six months of 2015, total production was 33.3 MMBOE up 29% compared with 25.9 MMBOE in the first six months of 2014.



Production	2Q15	1Q15

Oil Production (MMBbls)	5.1	5.2
Gas Production (Bcf)	44.2	45.9
NGL Production (MMBbls)	4.0	3.9
Total Production (MMBOE)	16.5	16.8

Equivalent Daily Production (MBOE/d)	181.0	186.4

Pricing in the second quarter of 2015 reflected a 44% decline in WTI oil prices and a 41% decline in NYMEX natural gas prices from the prior year period. The Company had approximately 46% of oil production, 41% of natural gas production and no NGL production hedged during the quarter. The table below provides the average realized prices received by product, as well as the adjusted prices received after taking into account settlements for derivative transactions:



Average Realized Commodity Prices for the Three Months Ended June 30, 2015
	Before the effect of derivative settlements	After the effect of derivative settlements

Oil ($/Bbl)	$51.45	$65.98
Gas ($/Mcf)	$2.53	$3.41
Natural gas liquids ($/Bbl)	$16.85	$16.85
Equivalent ($/BOE)	$26.78	$33.63

Operating costs in the second quarter of 2015 included lease operating expenses of $3.26 per BOE and transportation expenses of $5.64 per BOE, each of which reflect cost improvements compared with the second quarter of 2014 and sequentially from the first quarter of 2015, as well as lower costs than budgeted. The overall operating cost environment has improved at a more rapid pace than expected at the beginning of 2015. In addition, the Company has realized efficiencies at key assets, specifically at the Williston Basin acquired properties. Transportation costs benefited from lower deficiency fees and lower trucking costs.

General and administrative expenses before non-cash compensation include an approximate $5 million charge related to closure of the Tulsa, Oklahoma office.

Costs per BOE were as follows:



Costs	2Q15	1Q15

LOE ($/BOE)	$3.26	$3.96
Ad Valorem ($/BOE)	$0.25	$0.52
Transportation ($/BOE)	$5.64	$6.08
Production taxes (% of pre-derivative oil, gas, and NGL revenue)	5.2%	4.8%

G&A - Cash ($/BOE)	$2.26	$2.34
G&A - Non-cash ($/BOE)	$0.33	$0.26
Total G&A ($/BOE)	$2.59	$2.60

DD&A ($/BOE)	$13.34	$12.96

Net loss for the second quarter of 2015 was $57.5 million, or $(0.85) per diluted common share, compared with net income of $59.8 million, or $0.88 per diluted common share, in the second quarter of 2014. For the first six months of 2015, the Company's net loss was $110.6 million, or $(1.64) per diluted common share, compared with net income of $125.4 million, or $1.84 per diluted common share, in the prior year period.

Adjusted net income for the second quarter of 2015 was $33.2 million or $0.49 per diluted common share, compared with adjusted net income of $106.5 million, or $1.56 per diluted common share, in the second quarter of 2014. Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and are generally items whose timing and/or amount cannot be reasonably estimated.

Adjusted earnings before interest, taxes, depletion, amortization and accretion, and exploration expense, or adjusted EBITDAX, was $337.3 million for the second quarter of 2015 compared with $423.4 million in the second quarter of 2014. Lower adjusted EBITDAX is primarily a result of significantly lower commodity prices in the second quarter of 2015, partially offset by higher production and lower costs discussed above.

Adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the Financial Highlights section at the end of this release for additional information about these measures.

CAPITAL, OPERATIONS AND GUIDANCE

Capital Expenditures

The Company’s total 2015 capital expenditures are estimated at approximately $1.28 billion, up approximately $50 million from its original budget, and includes drilling approximately 132 gross/119 net operated wells and participation in 43 net non-operated wells. Second quarter of 2015 capital expenditures were $339 million, down approximately 30% from the first quarter of 2015. The Company completed approximately two-thirds of its capital activity in the first six months of 2015. During the first half of the year, drilling and completion costs were reduced significantly across the Company's areas of operations due to a combination of lower service company rates and increased efficiencies. The Company expects capital expenditures to step down in each of the third and fourth quarters of 2015.

The 2015 drilling program is focused in the Eagle Ford shale and Bakken/Three Forks plays. The Company currently has nine active rigs with four in the Eagle Ford, four in the Bakken/Three Forks and one in the Powder River Basin. The Company anticipates releasing two Bakken/Three Forks rigs in the fall of 2015.

Eagle Ford

Second quarter of 2015 net production averaged 130.8 MBOE/d, including both operated and non-operated wells. Production was affected by planned shut-ins, predominantly due to third party maintenance at gathering facilities; however, production exceeded expectations due to improved well performance. The Company made 18 flowing completions during the quarter, including 14 wells from its down-spacing test in the Eagle Ford East area. Current well costs are down more than 30% compared with similarly designed wells in 2014.

While still early, results from the Company's pilot down-spacing test are encouraging and trending above expectations as well as the Company's previously disclosed type curve for the area.

Bakken/Three Forks

Second quarter of 2015 production from the Company's Bakken/Three Forks program averaged 24.1 MBOE/d and was 86% oil. The Company has moved to plug-and-perf/cemented liner completions in its Bakken/Three Forks program, which are demonstrating improved well performance compared to prior completion techniques. At the end of June 2015, the Company had 37 drilled but uncompleted wells in its operated program.

Cumulative production from nine wells (including five new wells) in Divide County, North Dakota testing the Bakken interval is continuing to perform above the Company's type curve expectations for the Three Forks interval in the area. The addition of the Bakken interval has the potential to significantly increase the Company's proved reserves and inventory of drilling locations in Divide County.

Guidance

The following table presents updated production and performance guidance for full year 2015:



Revised Guidance for 2015
	FY2015
Production (MMBOE)	61.5 - 64.0
Average daily production (MBOE/d)	168 - 175

LOE ($/BOE)	$3.60 - $4.00
Ad Valorem ($/BOE)	$0.50 - $0.55
Transportation ($/BOE)	$6.25 - $6.55
Production taxes (% of pre-derivative oil, gas, and NGL revenue)	4.5% - 5.0%

G&A - Cash ($/BOE)	$2.40 - $2.70
G&A - Non-cash ($/BOE)	$0.30 - $0.40
Total G&A ($/BOE)	$2.70 - $3.10

DD&A ($/BOE)	$13.75 - $14.25

Effective income tax rate range	37.6% - 38.6%
% of income tax that is current	n/m

FINANCIAL POSITION AND LIQUIDITY

The Company ended the second quarter of 2015 with long-term debt of $2.47 billion including $2.35 billion in senior notes and $0.12 billion drawn on its revolving credit facility. During the quarter, the Company received $316.5 million in net proceeds, subject to post-closing adjustments, from the completion of divestitures of its Mid-Continent assets. The Company applied these proceeds to reduce the outstanding balance on its revolving credit facility. During the quarter, the Company redeemed $350 million of its 6.625% Senior Notes due 2019 and issued $500 million of its 5.625% Senior Notes due 2025.

For the second half of 2015, the Company has commodity derivative contracts in place representing approximately 46% of oil, 41% of natural gas and 46% of NGL forecasted volumes at the midpoint. Commodity derivative contracts through 2016 are as follows:



Derivative Position through 2016
as of July 22, 2015*
	Oil		Gas		NGL***
Period	Volume (MBbls)	Weighted Avg. Price** ($/Bbl)	Volume (BBTU)	Weighted Avg. Price** ($/MMBTU)	Volume (MBbls)	Weighted Avg. Price - Mont Belvieu ($/Bbl)
3Q15	2,160	$88.36	14,840	$4.05	1,739	$21.61
4Q15	2,006	$87.92	17,656	$4.07	1,539	$21.73
1Q16	1,868	$86.93	16,171	$4.30	685	$22.33
2Q16	1,752	$86.73	9,130	$4.05	622	$22.39
3Q16	1,170	$90.29	7,005	$4.09	369	$9.12
4Q16	780	$90.05	12,866	$4.10	341	$9.12

* Includes all commodity derivative contracts for settlement at any time during the third quarter of 2015 and later periods, entered into as of 7/22/15.
** Weighted average prices are shown as NYMEX equivalents. For collars, floor prices were used to calculate the weighted average price.
***NGL derivative positions include: 3Q15-2Q16 propane and butanes only; 3Q16-4Q16 ethane only.

EARNINGS CALL INFORMATION

The Company has scheduled a webcast and conference call to discuss second quarter 2015 financial and operational results as well as provide more detailed discussion on well results from the Eagle Ford and Bakken/Three Forks programs. The webcast is scheduled for July 29, 2015, at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). The webcast can be accessed from the Company's website at www.sm-energy.com, which will remain available for replay for approximately 30 days. You may also join via teleconference at the dial-in information below. A telephonic replay of the call will be available approximately two hours after the call through August 12, 2015.



Call Type	Phone Number	Conference ID
Domestic Participant	877-303-1292	85327552
Domestic Replay	855-859-2056	85327552
International Participant	315-625-3086	85327552
International Replay	404-537-3406	85327552

This call is being webcast live and can be accessed at SM Energy Company's website at www.sm-energy.com. An audio recording of the conference call will be available at that site through August 12, 2015.

INFORMATION ABOUT FORWARD LOOKING STATEMENTS

This release contains forward looking statements within the meaning of securities laws, including forecasts and projections. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will” and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward looking statements. These risks include factors such as the availability,

proximity and capacity of gathering, processing and transportation facilities; the uncertainty of negotiations to result in an agreement or a completed transaction; the uncertain nature of announced acquisition, divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected acquisition, divestiture, joint venture, farm down or similar efforts; the volatility and level of oil, natural gas, and natural gas liquids prices; uncertainties inherent in projecting future rates of production from drilling activities and acquisitions; the imprecise nature of estimating oil and gas reserves; the availability of additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other such matters discussed in the “Risk Factors” section of SM Energy's 2014 Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission. The forward looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by securities laws.

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:

MEDIA:

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

INVESTORS:

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

James Edwards, jedwards@sm-energy.com, 303-837-2444



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2015

Production Data	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015		2014			Percent Change	2015		2014			Percent Change

Average realized sales price, before the effects of
derivative settlements:
Oil (per Bbl)	$	51.45	$	91.78		(44)%	$	44.92	$	90.41		(50)%
Gas (per Mcf)	2.53		4.87			(48)%	2.65		5.04			(47)%
NGL (per Bbl)	16.85		35.61			(53)%	16.76		37.13			(55)%
Equivalent (per BOE)	$	26.78	$	48.93		(45)%	$	25.10	$	49.43		(49)%

Average realized sales price, including the effects of
derivative settlements:
Oil (per Bbl)	$	65.98	$	86.60		(24)%	$	62.39	$	86.85		(28)%
Gas (per Mcf)	3.41		4.51			(24)%	3.46		4.67			(26)%
NGL (per Bbl)	16.85		35.59			(53)%	19.39		35.67			(46)%
Equivalent (per BOE)	$	33.63	$	46.41		(28)%	$	33.34	$	47.00		(29)%

Net production volumes:
Oil (MMBbl)	5.1		3.9			31%	10.3		7.5			37%
Gas (Bcf)	44.2		38.0			16%	90.1		73.5			23%
NGL (MMBbl)	4.0		3.2			27%	7.9		6.1			31%
MMBOE	16.5		13.4			23%	33.3		25.9			29%

Average net daily production:
Oil (MBbl per day)	55.9		42.8			31%	57.0		41.7			37%
Gas (MMcf per day)	485.8		417.2			16%	498.0		406.1			23%
NGL (MBbl per day)	44.2		34.7			27%	43.8		33.4			31%
MBOE (per day)	181.0		147.0			23%	183.7		142.8			29%

Per BOE Data:
Realized price before the effects of derivative settlements	$	26.78	$	48.93		(45)%	$	25.10	$	49.43		(49)%
Lease operating expense	3.26		4.17			(22)%	3.62		4.12			(12)%
Transportation costs	5.64		6.20			(9)%	5.86		6.27			(7)%
Production taxes	1.39		2.38			(42)%	1.25		2.29			(45)%
Ad valorem tax expense	0.25		0.52			(52)%	0.39		0.52			(25)%
General and administrative	2.59		2.85			(9)%	2.59		2.83			(8)%
Operating profit, before the effects of derivative settlements	$	13.65	$	32.81		(58)%	$	11.39	$	33.40		(66)%
Derivative settlements	6.85		(2.52		)	372%	8.24		(2.43		)	439%
Operating profit, including the effects of derivative settlements	$	20.50	$	30.29		(32)%	$	19.63	$	30.97		(37)%
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion	$	13.34	$	14.03		(5)%	$	13.14	$	14.12		(7)%



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2015

Condensed Consolidated Statements of Operations
(in thousands, except per share amounts)	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
Operating revenues:
Oil, gas, and NGL production revenue	$	441,256		$	654,661		$	834,571		$	1,277,770
Net gain on divestiture activity	71,884			2,526			36,082			5,484
Other operating revenues	3,006			17,793			11,427			24,446
Total operating revenues and other income	516,146			674,980			882,080			1,307,700

Operating expenses:
Oil, gas, and NGL production expense	173,685			177,598			369,836			341,307
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	219,704			187,781			437,105			364,996
Exploration	25,541			24,270			62,948			45,605
Impairment of proved properties	12,914			—			68,440			—
Abandonment and impairment of unproved properties	5,819			164			17,446			2,965
General and administrative	42,605			38,115			86,244			73,166
Change in Net Profits Plan liability	(4,476		)	(7,105		)	(8,810		)	(8,881		)
Derivative (gain) loss	80,929			126,469			(73,238		)	224,131
Other operating expenses	10,304			5,972			27,423			14,061
Total operating expenses	567,025			553,264			987,394			1,057,350

Income (loss) from operations	(50,879		)	121,716			(105,314		)	250,350

Non-operating income (expense):
Other, net	25			(1,847		)	596			(1,821		)
Interest expense	(30,779		)	(24,040		)	(63,426		)	(48,230		)
Loss on extinguishment of debt	(16,578		)	—			(16,578		)	—

Income (loss) before income taxes	(98,211		)	95,829			(184,722		)	200,299
Income tax (expense) benefit	40,703			(36,049		)	74,156			(74,912		)

Net income (loss)	$	(57,508	)	$	59,780		$	(110,566	)	$	125,387

Basic weighted-average common shares outstanding	67,483			67,069			67,473			67,063

Diluted weighted-average common shares outstanding	67,483			68,239			67,473			68,180

Basic net income (loss) per common share	$	(0.85	)	$	0.89		$	(1.64	)	$	1.87

Diluted net income (loss) per common share	$	(0.85	)	$	0.88		$	(1.64	)	$	1.84



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2015

Condensed Consolidated Balance Sheets
(in thousands, except share amounts)	June 30,			December 31,
ASSETS	2015			2014
Current assets:
Cash and cash equivalents	$	82		$	120
Accounts receivable	239,983			322,630
Derivative asset	269,022			402,668
Prepaid expenses and other	16,621			19,625
Total current assets	525,708			745,043

Property and equipment (successful efforts method):
Proved oil and gas properties	7,356,877			7,348,436
Less - accumulated depletion, depreciation, and amortization	(3,073,603		)	(3,233,012		)
Unproved oil and gas properties	419,903			532,498
Wells in progress	419,979			503,734
Oil and gas properties held for sale net of accumulated depletion, depreciation and amortization of $30,514 and $22,482, respectively	7,361			17,891
Other property and equipment, net of accumulated depreciation of $38,051 and $37,079, respectively	354,528			334,356
Total property and equipment, net	5,485,045			5,503,903

Noncurrent assets:
Derivative asset	131,464			189,540
Other noncurrent assets	71,401			78,214
Total other noncurrent assets	202,865			267,754
Total Assets	$	6,213,618		$	6,516,700

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	423,536		$	640,684
Derivative liability	8,107			—
Deferred tax liability	90,514			142,976
Other current liabilities	—			1,000
Total current liabilities	522,157			784,660

Noncurrent liabilities:
Revolving credit facility	122,000			166,000
Senior Notes	2,350,000			2,200,000
Asset retirement obligation	115,276			120,867
Net Profits Plan liability	18,326			27,136
Deferred income taxes	859,588			891,681
Derivative liability	1,026			70
Other noncurrent liabilities	36,938			39,631
Total noncurrent liabilities	3,503,154			3,445,385

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 67,598,649 and 67,463,060, respectively	676			675
Additional paid-in capital	299,637			283,295
Retained earnings	1,900,058			2,013,997
Accumulated other comprehensive loss	(12,064		)	(11,312		)
Total stockholders’ equity	2,188,307			2,286,655
Total Liabilities and Stockholders’ Equity	$	6,213,618		$	6,516,700



FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2015

Condensed Consolidated Statements of Cash Flows
(in thousands)
	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
Cash flows from operating activities:
Net income (loss)	$	(57,508	)	$	59,780		$	(110,566	)	$	125,387
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain on divestiture activity	(71,884		)	(2,526		)	(36,082		)	(5,484		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	219,704			187,781			437,105			364,996
Exploratory dry hole expense	6,621			6,459			22,896			6,459
Impairment of proved properties	12,914			—			68,440			—
Abandonment and impairment of unproved properties	5,819			164			17,446			2,965
Stock-based compensation expense	7,191			7,997			13,215			14,341
Change in Net Profits Plan liability	(4,476		)	(7,105		)	(8,810		)	(8,881		)
Derivative (gain) loss	80,929			126,469			(73,238		)	224,131
Derivative cash settlements	131,486			(33,680		)	291,619			(62,620		)
Amortization of deferred financing costs	1,935			1,477			3,892			2,954
Non-cash loss on extinguishment of debt	4,123			—			4,123			—
Deferred income taxes	(50,829		)	35,537			(84,556		)	73,911
Plugging and abandonment	(961		)	(1,894		)	(3,386		)	(3,219		)
Other, net	(1,930		)	(1,724		)	(434		)	(4,827		)
Changes in current assets and liabilities:
Accounts receivable	(30,576		)	(11,905		)	38,951			(2,558		)
Prepaid expenses and other	1,652			417			2,933			1,302
Accounts payable and accrued expenses	11,376			48,178			(34,040		)	(13,704		)
Net cash provided by operating activities	265,586			415,425			549,508			715,153

Cash flows from investing activities:
Net proceeds from sale of oil and gas properties	313,415			44,842			334,988			46,821
Capital expenditures	(429,165		)	(426,646		)	(974,130		)	(778,580		)
Acquisition of proved and unproved oil and gas properties	3,481			(98,814		)	(6,588		)	(98,619		)
Other, net	1			(6,484		)	(996		)	(2,257		)
Net cash used in investing activities	(112,268		)	(487,102		)	(646,726		)	(832,635		)

Cash flows from financing activities:
Proceeds from credit facility	670,500			—			1,230,500			—
Repayment of credit facility	(965,000		)	—			(1,274,500		)	—
Net proceeds from Senior Notes	491,557			—			491,557			—
Repayment of Senior Notes	(350,000		)	—			(350,000		)	—
Proceeds from sale of common stock	3,157			2,490			3,157			2,490
Dividends paid	(3,373		)	(3,353		)	(3,373		)	(3,353		)
Other, net	(99		)	(101		)	(161		)	(109		)
Net cash provided by (used in) financing activities	(153,258		)	(964		)	97,180			(972		)

Net change in cash and cash equivalents	60			(72,641		)	(38		)	(118,454		)
Cash and cash equivalents at beginning of period	22			236,435			120			282,248
Cash and cash equivalents at end of period	$	82		$	163,794		$	82		$	163,794



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2015

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

Reconciliation of net income (loss) (GAAP)
to adjusted net income (Non-GAAP):
	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014

Reported net income (loss) (GAAP)	$	(57,508	)	$	59,780		$	(110,566	)	$	125,387

Adjustments net of tax: ⁽¹⁾
Change in Net Profits Plan liability	(2,829		)	(4,462		)	(5,568		)	(5,577		)
Derivative (gain) loss	51,147			79,423			(46,286		)	140,754
Derivative settlement gain (loss) ⁽²⁾	71,286			(21,151		)	173,183			(39,325		)
Gain on divestiture activity	(45,431		)	(1,586		)	(22,804		)	(3,444		)
Impairment of proved properties	8,162			—			43,254			—
Abandonment and impairment of unproved properties	3,678			103			11,026			1,862
Loss on extinguishment of debt	10,477			—			10,477			—
Unwinding of derivatives contracts related to Mid-contintent	(9,688		)	—			(9,688		)	—
Other, net ⁽³⁾	3,858			(5,558		)	4,774			(5,558		)

Adjusted net income (Non-GAAP)⁽⁴⁾	$	33,152		$	106,549		$	47,802		$	214,099

Diluted weighted-average common shares outstanding: ⁽⁵⁾	68,073			68,239			67,963			68,180

Adjusted net income per diluted common share:	$	0.49		$	1.56		$	0.70		$	3.14

(1) Adjustments are shown net of tax and are calculated using a tax rate of 36.8% for the three and six months ended June 30, 2015, and 37.2% for the three and six months ended June 30, 2014, which approximates the Company's statutory tax rate for the respective periods, as adjusted for ordinary permanent differences.
(2) Derivative settlement gain (loss) is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.
(3) For the three and six-month period ended June 30, 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
(4) Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and generally are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash adjustments and impairments such as the change in the Net Profits Plan liability, derivative (gain) loss net of derivative settlements, impairment of properties, and (gain) loss on divestiture activity. The non-GAAP measure of adjusted net income 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 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 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 excludes some, but not all, items that affect net income and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies.
(5) For periods where the Company reports a GAAP net loss, the diluted weighted average share count is calculated using potentially dilutive securities related to unvested Restricted Stock Units and contingent Performance Share Units. On a GAAP basis, these items are not treated as dilutive securities in periods where the Company reports a GAAP loss for the quarter.



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2015
Adjusted EBITDAX ⁽³⁾
(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 Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
Net income (loss) (GAAP)	$	(57,508	)	$	59,780		$	(110,566	)	$	125,387
Interest expense	30,779			24,040			63,426			48,230
Other non-operating (income) expense, net	(25		)	1,847			(596		)	1,821
Income tax expense (benefit)	(40,703		)	36,049			(74,156		)	74,912
Depreciation, depletion, amortization, and asset retirement obligation liability accretion	219,704			187,781			437,105			364,996
Exploration⁽¹⁾	23,768			22,603			59,500			42,541
Impairment of proved properties	12,914			—			68,440			—
Abandonment and impairment of unproved properties	5,819			164			17,446			2,965
Stock-based compensation expense	7,191			7,997			13,215			14,341
Derivative (gain) loss	80,929			126,469			(73,238		)	224,131
Derivative settlement gain (loss) ⁽²⁾	112,795			(33,680		)	274,024			(62,620		)
Change in Net Profits Plan liability	(4,476		)	(7,105		)	(8,810		)	(8,881		)
Net gain on divestiture activity	(71,884		)	(2,526		)	(36,082		)	(5,484		)
Loss on extinguishment of debt	16,578			—			16,578			—
Other, net	1,406			—			2,856			—
Adjusted EBITDAX (Non-GAAP)	337,287			423,419			649,142			822,339
Interest expense	(30,779		)	(24,040		)	(63,426		)	(48,230		)
Other non-operating income (expense), net	25			(1,847		)	596			(1,821		)
Income tax (expense) benefit	40,703			(36,049		)	74,156			(74,912		)
Exploration ⁽¹⁾	(23,768		)	(22,603		)	(59,500		)	(42,541		)
Exploratory dry hole expense	6,621			6,459			22,896			6,459
Amortization of deferred financing costs	1,935			1,477			3,892			2,954
Deferred income taxes	(50,829		)	35,537			(84,556		)	73,911
Plugging and abandonment	(961		)	(1,894		)	(3,386		)	(3,219		)
Loss on extinguishment of debt	(12,455		)	—			(12,455		)	—
Other, net	(3,336		)	(1,724		)	(3,290		)	(4,827		)
Changes in current assets and liabilities	1,143			36,690			25,439			(14,960		)
Net cash provided by operating activities (GAAP)	$	265,586		$	415,425		$	549,508		$	715,153

⁽¹⁾ Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying condensed consolidated statements of operations because of the component of stock-based compensation expense recorded to exploration.
⁽²⁾ Derivative settlement gain (loss) is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.

⁽³⁾ Adjusted EBITDAX represents income (loss) before interest expense, other non-operating income or expense, income taxes, depreciation, depletion, amortization, and accretion, exploration expense, property impairments, non-cash stock 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 that 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 and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.