EXHIBIT 99.1


FOR IMMEDIATE RELEASE


SM ENERGY REPORTS THIRD QUARTER OF 2015 RESULTS -
EXCEEDING EXPECTATIONS FOR 2015 THROUGH EFFICIENCIES AND PERFORMANCE

Produced 16.1 million barrels of oil equivalent (MMBOE), up 22% from the prior year period and above plan
Realized $259.4 million adjusted EBITDAX (see GAAP reconciliations below), exceeding the Company's expectations
Maintained modest debt to adjusted TTM EBITDAX at 1.9 times
Monitored 130 days of success with Eagle Ford Pilot Test #1, which supports downspacing in Eagle Ford East
Achieving substantial progress in well performance and cost efficiencies

DENVER, CO October 27, 2015 - SM Energy Company (NYSE: SM) announces its financial results for the third quarter of 2015 and provides an operations update. In conjunction with this release, the Company posted an investor presentation with additional third quarter earnings and operations detail to 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 October 28, 2015. Information for the call can be found below.

MANAGEMENT COMMENTARY
Comments from President and Chief Executive Officer Jay Ottoson: "I am pleased to report another excellent quarter with production and EBITDAX that exceeded our internal forecasts. Third quarter production was up sequentially from the second quarter (adjusted for assets sold in the second quarter) and up 22% compared with the third quarter last year.

"Operational execution continues to drive our outperformance.  We are working hard to reduce costs and apply technology effectively on a number of fronts.  We are reducing drilling times, optimizing completions and generating better well results in our core development programs. For example, drilling and completion costs for our operated Eagle Ford wells in the third quarter were down nearly 50% from our 2014 average. At the same time, we have been conducting several pilot tests in high productivity areas of the Eagle Ford and Bakken/Three Forks intended to prove up additional economic drilling inventory. Test results to date have been positive and have translated into higher than forecast production.

"Looking into 2016, we plan to focus our activity on our programs that generate the best returns. Our diligent efforts to reduce costs and improve well performance will continue, and we expect to allocate an increased portion of capital to the Permian and Williston Basins.  Fundamental to the 2016 operating plan will be aligning capital spending with estimated EBITDAX to optimize cash flow and inventory expansion, resulting in differential value creation in 2016."

 






THIRD QUARTER 2015 RESULTS    
Production for the third quarter of 2015 was 16.1 MMBOE, or 174.5 MBOE/d, up 22% compared with 13.1 MMBOE, or 142.5 MBOE/d, in the third quarter of 2014. Total production increased sequentially, adjusted for second quarter assets sales, and exceeded the Company's expectations by approximately 0.6 MMBOE, despite an 11% sequential decline in non-operated Eagle Ford production.
Strong production was driven by well performance in the Company's core areas that continues to exceed the Company's year-end 2014 type curves plus a number of positive test wells in the Eagle Ford that came on sales during the quarter. Specifically, Eagle Ford Test #1 reached a peak natural gas rate of 105 MMcf/d during the quarter and Test #3 is on sales with several wells producing more than 10 MMcf/d each, while still cleaning up. Of note, these tests were drilled in high natural gas content areas, increasing the mix of natural gas in total third quarter production.  The production mix for the quarter was 28% oil, 45% natural gas and 27% natural gas liquids ("NGLs"). For the first nine months of 2015, total production was 49.3 MMBOE, up 27% compared with 39.0 MMBOE in the first nine months of 2014.
Sequential Production
Production
3Q15
 
2Q15*
 
 
 
 
Oil Production (MMBbls)
4.5

 
5.1

Gas Production (Bcf)
43.3

 
40.3

NGL Production (MMBbls)
4.3

 
4.0

Total Production (MMBOE)
16.1

 
15.8

 
 
 
 
Equivalent Daily Production (MBOE/d)
174.5

 
173.6

*2Q15 production adjusted for asset sales completed during that quarter.

Pricing in the third quarter of 2015 reflected a 52% decline in WTI oil prices, a 30% decline in NYMEX natural gas prices and a 54% decline in OPIS NGL prices from the prior year period. The Company had approximately 48% of oil production, 34% of natural gas production and 40% of 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 September 30, 2015
 
Before the effect of derivative settlements
 
After the effect of derivative settlements
 
 
 
 
Oil ($/Bbl)
$40.03
 
$60.05
Gas ($/Mcf)
$2.77
 
$3.22
Natural gas liquids ($/Bbl)
$15.18
 
$16.12
Equivalent ($/BOE)
$22.84
 
$29.92

Operating costs in the third quarter of 2015 included lease operating expenses of $3.86 per BOE, down $0.72 per BOE from the prior year period, and transportation expenses of $6.27 per BOE, up $0.05 per BOE from the prior year period. Lease operating expenses on the Company’s operated properties tracked internal forecasts and included planned higher workover expenses compared with the second quarter of 2015. Third quarter lease operating expenses at the Company’s non-operated Eagle Ford properties increased Company-wide lease operating



expenses $0.20 per BOE sequentially. For the first nine months of 2015, lease operating expenses averaged $3.70 per BOE and transportation costs averaged $5.99 per BOE, down 13% and 4%, respectively.
General and administrative expenses for the third quarter of 2015 were $37.8 million, or $2.35 per BOE. Net of non-cash compensation expenses of $5.4 million, general and administrative expenses were $32.4 million, or $2.02 per BOE. General and administrative expenses per BOE were down significantly compared with the prior year periods, down 26% in the third quarter and down 15% in the first nine months.
Net income for the third quarter of 2015 was $3.1 million, or $0.05 per diluted common share, compared with net income of $208.9 million, or $3.05 per diluted common share, in the third quarter of 2014. For the first nine months of 2015, the Company's net loss was $107.5 million, or $1.59 per diluted common share, compared with net income of $334.3 million, or $4.90 per diluted common share, in the prior year period.
Adjusted net loss for the third quarter of 2015 was $23.3 million, or $0.34 per diluted common share, compared with adjusted net income of $98.6 million, or $1.44 per diluted common share, in the third quarter of 2014. Lower adjusted net income is predominantly due to the 51% decline in average prices received per BOE, partially offset by the 22% increase in production and 15% decrease in production costs per BOE. 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 $259.4 million for the third quarter of 2015, compared with $406.2 million in the third quarter of 2014. Lower adjusted EBITDAX is primarily a result of significantly lower commodity prices in the third quarter of 2015, partially offset by higher production and lower costs per BOE, as 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. Capital expenditures through the first nine months totaled approximately $1.1 billion.
The Company's 2015 drilling program is primarily focused on its Eagle Ford shale and Bakken/Three Forks plays. Third quarter of 2015 capital expenditures were $277 million, down approximately 18% from the second quarter of 2015, as the Company reduced its drilling activity from nine rigs at the end of the second quarter to seven rigs currently. The Company's seven active operated rigs include four in the Eagle Ford, two in the Bakken/Three Forks and one in the Powder River Basin. At year-end, the Company anticipates releasing one rig from its Eagle Ford program and adding one rig in the Permian Basin. The Company is currently deferring most completions in both its Eagle Ford and Bakken/Three Forks programs and plans to increase completion activity around year-end.





Eagle Ford
Third quarter of 2015 net production averaged 134.5 BOE/d, including both operated and non-operated wells. Daily production increased 31% from the third quarter of 2014 and increased 3% sequentially from the second quarter of 2015, despite an 11% sequential decline in non-operated production from the area.
The focus on operational execution in the operated Eagle Ford is resulting in a number of quantifiable results. For example, comparison of third quarter of 2015 data with 2014 full year averages shows a 54% decline in completion costs per lateral foot and a 28% reduction in drilling costs per lateral foot. The average days from spud-to-rig per 1000 feet of total measured depth improved approximately 14% in the program.
The Company has scheduled nine Eagle Ford multi-well pilot tests intended to test the potential for inventory expansion across its acreage position through downspacing, infill drilling and the addition of the Upper Eagle Ford interval. Wells have been drilled and completed in five of the nine tests, with the remaining tests expected to be completed in 2016. To date, Eagle Ford test results are encouraging. On Test #1, a 14-well test of downspacing to 450 feet, the Company has approximately 130 days of sales. This successful test to date provides the Company with confidence that future drilling programs in the East Area can support 450 foot well-spacing. Test #3, a 5-well test of the Upper and Lower Eagle Ford intervals, includes 312 foot plan-view spacing. While this test is in a dry natural gas area, its broader implications are important as to date it appears to extend the footprint of the Company's Upper Eagle Ford to the south and support the potential for higher density plan-view spacing throughout the Company's 250-350 foot thick Eagle Ford shale position. Tests #2 through #5 are completed and either on flowback or have too few days of production to report.
Bakken/Three Forks
Third quarter of 2015 production from the Company's Bakken/Three Forks program averaged 22.2 MBOE/d and was 85% oil. Production increased 27% from the third quarter of 2014 and decreased 7% sequentially, as the Company continues to actively drill in the area but not complete all wells drilled. As of the end of the third quarter of 2015, the Company had an inventory of 47 gross and 39 net operated wells drilled and uncompleted in the area.
The Company's operations have focused on drilling and completion efficiencies. Drilling days in 2015 are down 11% on average from 2014 and the Company recently drilled a Divide County Bakken well, spud to rig release, in 10 days. Enhanced completions are driving 20%-30% increased recoveries per well as the Company employs plug-and-perf/cemented liner completions. Overall, costs in the area have been reduced by 20%-25% per well compared with similar wells in 2014.
Cumulative production from nine wells in Divide County, North Dakota testing the Bakken interval continues to perform above the Company's type curve expectations for the Three Forks interval, demonstrating the economic viability of Bakken locations in the area. Two additional Bakken wells were recently completed farther south on the Company's acreage, which could expand the potential of the Bakken interval to the south. The addition of the Bakken interval has the potential to significantly increase the Company's proved reserves and the inventory of drilling locations in Divide County.





Guidance
The Company has slightly modified full year 2015 guidance to narrow certain ranges. In addition, the Company has slightly increased the mid-point of production guidance and has slightly lowered the mid-point of transportation and ad valorem tax cost guidance. The following table presents updated production and performance guidance for full year 2015:

Revised Guidance for 2015
 
 
FY2015
Production (MMBOE)
63.6 - 64.4
Average daily production (MBOE/d)
174 - 176
 
 
LOE ($/BOE)
$3.70 - $3.90
Ad Valorem ($/BOE)
$0.45 - $0.50
Transportation ($/BOE)
$6.10 - $6.25
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
39.6% - 40.6%

FINANCIAL POSITION AND LIQUIDITY

The Company ended the third quarter of 2015 with long-term debt of $2.53 billion, including $2.35 billion in senior notes and $0.18 billion drawn on its revolving credit facility. As previously reported, under the Company’s credit facility, the borrowing base is $2.0 billion and aggregate commitments are $1.5 billion, providing the Company with ample liquidity.
The Company has commodity derivative contracts in place for the fourth quarter of 2015 representing approximately 43% of oil, 45% of natural gas and 48% of NGL forecast volumes at the midpoint, and for 2016 representing approximately 30% of oil, 50% of natural gas and 50% of NGL, assuming 2015 exit rate production. A summary of commodity derivative contracts through 2016 are as follows:
    



Derivative Position through 2016
as of October 21, 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)
4Q15
2,006

$87.92
17,656

$4.07
1,709

$21.58
1Q16
1,868

$86.93
23,341

$3.90
2,250

$15.67
2Q16
1,752

$86.73
20,780

$3.39
2,018

$15.71
3Q16
1,170

$90.29
18,829

$3.33
1,613

$14.22
4Q16
780

$90.05
17,236

$3.83
1,280

$13.32
 
 
 
 
 
 
 
* Includes all commodity derivative contracts for settlement at any time during the fourth quarter of 2015 and later periods, entered into as of 10/21/15.
** Weighted average prices are shown as NYMEX equivalents. For collars, floor prices were used to calculate the weighted average price.
***NGL derivative positions include: 4Q15-2Q16 propane, ethane and butanes only; 3Q16-4Q16 propane and ethane only.
EARNINGS CALL INFORMATION

The Company has scheduled a webcast and conference call to discuss third quarter 2015 financial and operational results. The webcast is scheduled for October 28, 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, and 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 November 11, 2015.

Call Type
 
Phone Number
 
Conference ID
Domestic Participant
 
877-303-1292
 
57682556
Domestic Replay
 
855-859-2056
 
57682556
International Participant
 
315-625-3086
 
57682556
International Replay
 
404-537-3406
 
57682556

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 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 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:

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

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









SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
Production Data
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2015
 
2014
 
Percent Change
 
2015
 
2014

Percent Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average realized sales price, before the effects of
 
 
 
 
 
 
 
 
 
 
 
 
derivative settlements:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
40.03

 
$
86.56

 
(54)%
 
$
43.43

 
$
89.08

 
(51)%
 
Gas (per Mcf)
2.77

 
4.49

 
(38)%
 
2.69

 
4.86

 
(45)%
 
NGL (per Bbl)
15.18

 
34.86

 
(56)%
 
16.20

 
36.34

 
(55)%
 
Equivalent (per BOE)
$
22.84

 
$
47.06

 
(51)%
 
$
24.36

 
$
48.63

 
(50)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average realized sales price, including the effects of
 
 
 
 
 
 
 
 
 
 
 
 
derivative settlements:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
60.05

 
$
86.44

 
(31)%
 
$
61.67

 
$
86.71

 
(29)%
 
Gas (per Mcf)
3.22

 
4.44

 
(27)%
 
3.38

 
4.60

 
(27)%
 
NGL (per Bbl)
16.12

 
35.47

 
(55)%
 
18.23

 
35.60

 
(49)%
 
Equivalent (per BOE)
$
29.92

 
$
47.04

 
(36)%
 
$
32.22

 
$
47.02

 
(31)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net production volumes:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
4.5

 
4.0

 
13%
 
14.8

 
11.6

 
28%
 
Gas (Bcf)
43.3

 
35.6

 
22%
 
133.5

 
109.1

 
22%
 
NGL (MMBbl)
4.3

 
3.2

 
35%
 
12.2

 
9.2

 
32%
 
MMBOE
16.1

 
13.1

 
22%
 
49.3

 
39.0

 
27%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average net daily production:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbl per day)
49.1

 
43.5

 
13%
 
54.3

 
42.3

 
28%
 
Gas (MMcf per day)
471.1

 
386.5

 
22%
 
488.9

 
399.5

 
22%
 
NGL (MBbl per day)
46.8

 
34.6

 
35%
 
44.8

 
33.8

 
32%
 
MBOE (per day)
174.5

 
142.5

 
22%
 
180.6

 
142.7

 
27%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Per BOE Data:
 
 
 
 
 
 
 
 
 
 
 
 
Realized price, before the effects of derivative settlements
$
22.84

 
$
47.06

 
(51)%
 
$
24.36

 
$
48.63

 
(50)%
 
Lease operating expense
3.86

 
4.58

 
(16)%
 
3.70

 
4.27

 
(13)%
 
Transportation costs
6.27

 
6.22

 
1%
 
5.99

 
6.25

 
(4)%
 
Production taxes
0.96

 
2.32

 
(59)%
 
1.16

 
2.30

 
(50)%
 
Ad valorem tax expense
0.40

 
0.49

 
(18)%
 
0.39

 
0.51

 
(24)%
 
General and administrative
2.35

 
3.18

 
(26)%
 
2.52

 
2.95

 
(15)%
 
Operating profit, before the effects of derivative settlements
$
9.00

 
$
30.27

 
(70)%
 
$
10.60

 
$
32.35

 
(67)%
 
Derivative settlement gain (loss)
7.08

 
(0.02
)
 
35,500%
 
7.86

 
(1.61
)
 
588%
 
Operating profit, including the effects of derivative settlements
$
16.08

 
$
30.25

 
(47)%
 
$
18.46

 
$
30.74

 
(40)%
 
Depletion, depreciation, amortization, and
 
 
 
 
 
 
 
 
 
 
 
 
asset retirement obligation liability accretion
$
15.19

 
$
13.97

 
9%
 
$
13.81

 
$
14.07

 
(2)%
 




SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
 
 
 
 
 
 
 
 
 
Condensed Consolidated Statements of Operations
 
 
 
 
 
 
 
 
(in thousands, except per share amounts)
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
Operating revenues:
 
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
366,615

 
$
617,207

 
$
1,201,186

 
$
1,894,977

 
Net gain (loss) on divestiture activity
2,415

 
(5,432
)
 
38,497

 
52

 
Other operating revenues
2,121

 
7,011

 
13,548

 
31,457

 
Total operating revenues and other income
371,151

 
618,786

 
1,253,231

 
1,926,486

 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Oil, gas, and NGL production expense
184,568

 
178,390

 
554,404

 
519,697

 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
243,879

 
183,259

 
680,984

 
548,255

 
Exploration
19,679

 
34,556

 
82,627

 
80,161

 
Impairment of proved properties
55,990

 

 
124,430

 

 
Abandonment and impairment of unproved properties
6,600

 
15,522

 
24,046

 
18,487

 
General and administrative
37,782

 
41,696

 
124,026

 
114,862

 
Change in Net Profits Plan liability
(4,364
)
 
(6,399
)
 
(13,174
)
 
(15,280
)
 
Derivative (gain) loss
(212,253
)
 
(190,661
)
 
(285,491
)
 
33,470

 
Other operating expenses
7,166

 
5,444

 
34,589

 
19,505

 
Total operating expenses
339,047

 
261,807

 
1,326,441

 
1,319,157

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations
32,104

 
356,979

 
(73,210
)
 
607,329

 
 
 
 
 
 
 
 
 
 
Non-operating income (expense):
 
 
 
 
 
 
 
 
Other, net
27

 
(672
)
 
623

 
(2,493
)
 
Interest expense
(33,157
)
 
(22,621
)
 
(96,583
)
 
(70,851
)
 
Loss on extinguishment of debt

 

 
(16,578
)
 

 
 
 
 
 
 
 
 
 
 
Income (loss) before income taxes
(1,026
)
 
333,686

 
(185,748
)
 
533,985

 
Income tax (expense) benefit
4,140

 
(124,748
)
 
78,296

 
(199,660
)
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
3,114

 
$
208,938

 
$
(107,452
)
 
$
334,325

 
 
 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
67,961

 
67,379

 
67,638

 
67,169

 
 
 
 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
68,119

 
68,430

 
67,638

 
68,258

 
 
 
 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.05

 
$
3.10

 
$
(1.59
)
 
$
4.98

 
 
 
 
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.05

 
$
3.05

 
$
(1.59
)
 
$
4.90

 



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
 
 
 
 
Condensed Consolidated Balance Sheets
 
 
 
(in thousands, except share amounts)
September 30,
 
December 31,
 ASSETS
2015
 
2014
Current assets:
 
 
 
Cash and cash equivalents
$
197

 
$
120

Accounts receivable
171,067

 
322,630

Derivative asset
347,299

 
402,668

Prepaid expenses and other
19,114

 
19,625

Total current assets
537,677

 
745,043

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
7,468,331

 
7,348,436

Less - accumulated depletion, depreciation, and amortization
(3,240,109
)
 
(3,233,012
)
Unproved oil and gas properties
381,869

 
532,498

Wells in progress
452,436

 
503,734

Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $74,894 and $22,482, respectively
29,173

 
17,891

Other property and equipment, net of accumulated depreciation of $43,197 and $37,079, respectively
359,339

 
334,356

Total property and equipment, net
5,451,039

 
5,503,903

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
147,530

 
189,540

Other noncurrent assets
77,615

 
78,214

Total other noncurrent assets
225,145

 
267,754

Total Assets
$
6,213,861

 
$
6,516,700

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
361,734

 
$
640,684

Derivative liability
2,900

 

Deferred tax liability
120,563

 
142,976

Other current liabilities

 
1,000

Total current liabilities
485,197

 
784,660

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
184,000

 
166,000

Senior Notes
2,350,000

 
2,200,000

Asset retirement obligation
118,153

 
120,867

Net Profits Plan liability
13,962

 
27,136

Deferred income taxes
833,352

 
891,681

Derivative liability
2,019

 
70

Other noncurrent liabilities
40,341

 
39,631

Total noncurrent liabilities
3,541,827

 
3,445,385

 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 67,968,714 and 67,463,060, respectively
680

 
675

Additional paid-in capital
298,438

 
283,295

Retained earnings
1,899,803

 
2,013,997

Accumulated other comprehensive loss
(12,084
)
 
(11,312
)
Total stockholders’ equity
2,186,837

 
2,286,655

Total Liabilities and Stockholders’ Equity
$
6,213,861

 
$
6,516,700




FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
 
 
 
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows
 
 
 
 
 
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
Cash flows from operating activities:
 
 
 
 
 
 
 
 
Net income (loss)
$
3,114

 
$
208,938

 
$
(107,452
)
 
$
334,325

 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
 
Net (gain) loss on divestiture activity
(2,415
)
 
5,432

 
(38,497
)
 
(52
)
 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
243,879

 
183,259

 
680,984

 
548,255

 
Exploratory dry hole expense
(36
)
 
16,385

 
22,860

 
22,844

 
Impairment of proved properties
55,990

 

 
124,430

 

 
Abandonment and impairment of unproved properties
6,600

 
15,522

 
24,046

 
18,487

 
Stock-based compensation expense
7,277

 
10,227

 
20,492

 
24,568

 
Change in Net Profits Plan liability
(4,364
)
 
(6,399
)
 
(13,174
)
 
(15,280
)
 
Derivative (gain) loss
(212,253
)
 
(190,661
)
 
(285,491
)
 
33,470

 
Derivative cash settlements
105,688

 
(274
)
 
397,307

 
(62,894
)
 
Amortization of deferred financing costs
1,911

 
1,479

 
5,803

 
4,433

 
Non-cash loss on extinguishment of debt

 

 
4,123

 

 
Deferred income taxes
4,168

 
124,269

 
(80,388
)
 
198,180

 
Plugging and abandonment
(2,154
)
 
(2,974
)
 
(5,540
)
 
(6,193
)
 
Other, net
4,104

 
1,893

 
3,670

 
(2,934
)
 
Changes in current assets and liabilities:
 
 
 
 
 
 
 
 
Accounts receivable
66,385

 
9,034

 
105,336

 
6,476

 
Prepaid expenses and other
(2,346
)
 
(1,068
)
 
587

 
234

 
Accounts payable and accrued expenses
(40,207
)
 
(15,093
)
 
(74,247
)
 
(28,797
)
 
Net cash provided by operating activities
235,341

 
359,969

 
784,849

 
1,075,122

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
Net proceeds from the sale of oil and gas properties
115

 
(4,953
)
 
335,103

 
41,868

 
Capital expenditures
(287,741
)
 
(539,282
)
 
(1,261,871
)
 
(1,317,862
)
 
Acquisition of proved and unproved oil and gas properties
(500
)
 
(360,658
)
 
(7,088
)
 
(459,277
)
 
Other, net
6

 
1,543

 
(990
)
 
(714
)
 
Net cash used in investing activities
(288,120
)
 
(903,350
)
 
(934,846
)
 
(1,735,985
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
Proceeds from credit facility
374,000

 
536,500

 
1,604,500

 
536,500

 
Repayment of credit facility
(312,000
)
 
(146,500
)
 
(1,586,500
)
 
(146,500
)
 
Net proceeds from Senior Notes
(606
)
 

 
490,951

 

 
Repayment of Senior Notes

 

 
(350,000
)
 

 
Proceeds from sale of common stock

 
408

 
3,157

 
2,898

 
Dividends paid

 

 
(3,373
)
 
(3,353
)
 
Net share settlement from issuance of stock awards
(8,502
)
 
(10,576
)
 
(8,502
)
 
(10,576
)
 
Other, net
2

 
24

 
(159
)
 
(85
)
 
Net cash provided by financing activities
52,894

 
379,856

 
150,074

 
378,884

 
 
 
 
 
 
 
 
 
 
Net change in cash and cash equivalents
115

 
(163,525
)
 
77

 
(281,979
)
 
Cash and cash equivalents at beginning of period
82

 
163,794

 
120

 
282,248

 
Cash and cash equivalents at end of period
$
197

 
$
269

 
$
197

 
$
269

 




SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
 
 
 
 
 
 
 
 
 
Adjusted Net Income (Loss)
 
 
 
 
 
 
 
 
(in thousands, except per share data)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of net income (loss) (GAAP)
 
 
 
 
 
 
 
 
to adjusted net income (loss) (Non-GAAP):
 
 
 
 
 
 
 
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
Reported net income (loss) (GAAP)
$
3,114

 
$
208,938

 
$
(107,452
)
 
$
334,325

 
 
 
 
 
 
 
 
 
 
Adjustments net of tax: (1)
 
 
 
 
 
 
 
 
Change in Net Profits Plan liability
(2,758
)
 
(4,019
)
 
(8,326
)
 
(9,596
)
 
Derivative (gain) loss
(134,144
)
 
(119,735
)
 
(180,430
)
 
21,019

 
Derivative settlement gain (loss) (2)
71,855

 
(172
)
 
245,038

 
(39,497
)
 
Net (gain) loss on divestiture activity
(1,526
)
 
3,411

 
(24,330
)
 
(33
)
 
Impairment of proved properties
35,386

 

 
78,640

 

 
Abandonment and impairment of unproved properties
4,171

 
9,748

 
15,197

 
11,610

 
Loss on extinguishment of debt

 

 
10,477

 

 
Unwinding of derivatives contracts related to Mid-continent

 

 
(9,688
)
 

 
Other, net (3)
623

 
467

 
5,397

 
(5,092
)
 
 
 
 
 
 
 
 
 
 
Adjusted net income (loss) (Non-GAAP) (4)
$
(23,279
)
 
$
98,638

 
$
24,523

 
$
312,736

 
 
 
 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding: (5)
67,961

 
68,430

 
68,018

 
68,258

 
 
 
 
 
 
 
 
 
 
Adjusted net income (loss) per diluted common share:
$
(0.34
)
 
$
1.44

 
$
0.36

 
$
4.58

 
 
 
 
 
 
 
 
 
 
(1) Adjustments are shown net of tax and are calculated using a tax rate of 36.8% for the three and nine months ended September 30, 2015, and 37.2% for the three and nine months ended September 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 nine-month periods ended September 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. For the three and nine-month periods ended September 30, 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 expense, other, net, 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 period. Additionally, in periods where an adjusted net loss is calculated, all potentially dilutive shares are anti-dilutive and excluded from the calculation of adjusted net loss per diluted common share.
 



SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 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 September 30,
 
For the Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
Net income (loss) (GAAP)
$
3,114

 
$
208,938

 
$
(107,452
)
 
$
334,325

 
Interest expense
33,157

 
22,621

 
96,583

 
70,851

 
Other non-operating (income) expense, net
(27
)
 
672

 
(623
)
 
2,493

 
Income tax expense (benefit)
(4,140
)
 
124,748

 
(78,296
)
 
199,660

 
Depreciation, depletion, amortization, and asset retirement obligation liability accretion
243,879

 
183,259

 
680,984

 
548,255

 
Exploration (1)
17,798

 
32,155

 
77,298

 
74,696

 
Impairment of proved properties
55,990

 

 
124,430

 

 
Abandonment and impairment of unproved properties
6,600

 
15,522

 
24,046

 
18,487

 
Stock-based compensation expense
7,277

 
10,227

 
20,492

 
24,568

 
Derivative (gain) loss
(212,253
)
 
(190,661
)
 
(285,491
)
 
33,470

 
Derivative settlement gain (loss) (2)
113,695

 
(274
)
 
387,719

 
(62,894
)
 
Change in Net Profits Plan liability
(4,364
)
 
(6,399
)
 
(13,174
)
 
(15,280
)
 
Net (gain) loss on divestiture activity
(2,415
)
 
5,432

 
(38,497
)
 
(52
)
 
Loss on extinguishment of debt

 

 
16,578

 

 
Other, net
1,045

 

 
3,901

 

 
Adjusted EBITDAX (Non-GAAP)
259,356

 
406,240

 
908,498

 
1,228,579

 
Interest expense
(33,157
)
 
(22,621
)
 
(96,583
)
 
(70,851
)
 
Other non-operating income (expense), net
27

 
(672
)
 
623

 
(2,493
)
 
Income tax (expense) benefit
4,140

 
(124,748
)
 
78,296

 
(199,660
)
 
Exploration (1)
(17,798
)
 
(32,155
)
 
(77,298
)
 
(74,696
)
 
Exploratory dry hole expense
(36
)
 
16,385

 
22,860

 
22,844

 
Amortization of deferred financing costs
1,911

 
1,479

 
5,803

 
4,433

 
Deferred income taxes
4,168

 
124,269

 
(80,388
)
 
198,180

 
Plugging and abandonment
(2,154
)
 
(2,974
)
 
(5,540
)
 
(6,193
)
 
Loss on extinguishment of debt

 

 
(12,455
)
 

 
Other, net
3,059

 
1,893

 
(231
)
 
(2,934
)
 
Changes in current assets and liabilities
15,825

 
(7,127
)
 
41,264

 
(22,087
)
 
Net cash provided by operating activities (GAAP)
$
235,341

 
$
359,969

 
$
784,849

 
$
1,075,122

 
 
 
 
 
 
 
 
 
 
(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 expense, exploration expense, property 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 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.