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4th Quarter 2013
Earnings Call and
Operational Update
February 19, 2014
Forward Looking Statements - Cautionary Language
Except for historical information contained herein, statements in this presentation, including information regarding the business of the
Company, contain 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 2013 Annual Report on Form 10-K. 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.
Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire,
unless evidence indicates that renewal is reasonably certain. In this presentation, the Company uses the terms “probable,” “possible,”
“3P,” and “resources.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less
certain to be recovered than probable reserves. Reserves are estimated remaining quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date, by application of development projects to known accumulations (subject
to other conditions). Resources are quantities of oil and gas and related substances estimated to exist in naturally occurring
accumulations. SM Energy also uses the term “EUR” (estimated ultimate recovery), which is the sum of reserves remaining as of a
given date and cumulative production as of that date. Estimates of probable and possible reserves included in 3P reserves and
resources which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain
than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the
Company.
2
Key Messages
 SM Energy had record production
for the year.


Annual avg. daily production growth of 33%.



4Q12 to 4Q13 production growth of 31%.

 2013 was a strong year for proved
reserves.


Proved reserves grew 46% year over year.



Drilling F&D costs decreased by 26% year
over year.

 Balance sheet remains strong with
net Debt to TTM EBITDAX of <1x.
 SM Energy stock outperformed the
EPX index by 33 percentage points
in 2013, ending the year up 59%.

3
th
4

Quarter 2013 Performance

Production

4Q13 Actual
Performance

4Q13 Guidance

Net Income

143.8

139 - 146

Total production (MMBOE)

13.23

GAAP net income of
$7.0 million, or $0.10
per diluted share.



Average daily production (MBOE/d)



Adjusted net income*
(non-GAAP) of $85.9
million, or $1.26 per
adjusted diluted
share.

12.8 - 13.5

Costs
LOE ($/BOE)
Transportation ($/BOE)
Production taxes (% of pre-derivative
oil, gas, & NGL revenue)

$4.62
$5.67

G&A -- Cash ($/BOE)
G&A -- Cash NPP ($/BOE)
G&A -- Non-cash ($/BOE)
TOTAL G&A ($/BOE) **

$3.07
$0.17
$0.39
$3.63

$2.15 - $2.35
$0.25 - $0.40
$0.45 - $0.60
$2.85 - $3.35

$15.31

$15.00 - $16.00

DD&A ($/BOE)

4.5%

$4.65 - $4.90
$5.40 - $5.65
5.0% - 5.5%

EBITDAX


EBITDAX* (nonGAAP) of $395.5
million.

* Please see adjusted net income and EBITDAX reconciliations in the Appendix.
** 4Q13 G&A per unit expenses were higher than guidance due to performance-based bonus compensation.
4
2013
Proved Reserves and
Production
5
2013 Proved Reserve Roll-Forward
MMBOE

54%
Liquids/
46% Gas

600
500

53%
Liquids/
47% Gas

195.5

5.0

1.3

18.2

48.3

428.7

400

293.4

219.9

300
200

126.9
Proved Developed

100

Proved Undeveloped

208.9

166.5

0
Beginning
Proved Reserves

Adds/Infill

Acquisitions

Revisions

Divestitures

Production

Ending Proved
Reserves

 Proved reserves increased by 46% from 2012.
 Liquid volumes of proved reserves increased 49% year over year.
6
Reserve Metrics
 Drilling F&D decreased by approximately 26% in 2013
to $7.77 per BOE.
 Reserve replacement in excess of 400% for the second
consecutive year.

F&D $/BOE

$25.00
$20.00
$15.00

405%
$20.64

$17.10
$12.84

$10.00

$10.44

$5.00

$7.77

$0.00

2009

2010

Drilling F&D costs, excluding revisions

2011

2012

450%
400%
350%
300%
250%
200%
150%
100%
50%
0%

Reserve Replacement %

Reserve Metrics

2013

Drilling reserve replacement, excluding revisions
7
Annual Production
150

132.4

MBOE/d

125
99.7

100
75
50
25

49.8

50.2

17.3

77.5
9.6

16.7

32.5

32.8

2009

2010

38.2

28.3

17.4

22.1

26.0

45.8

54.7

2011

2012

NGL
Oil
Gas

68.2

0
2013

 2013 average daily annual production grew ~33% from 2012.
 3-year compounded annual average daily production growth of ~38%.
 Liquids volumes have increased 103% since 2011, when the Company began
reporting NGL volumes.
8
Debt Adjusted Metrics
BOE/D.A. Share

5.0

4.0
3.0

Proved reserves per debt
adjusted share
Production per debt
adjusted share
0.3

2.1

0.6

0.4

0.5

2.8

0.5
0.4

0.3

2.0
1.0

0.6

0.7

5.5
3.1

3.8

0.3
0.2

BOE/D.A. Share

6.0

0.1

0.0

0.0

2009

2010

2011

2012

2013



Proved reserves per debt adjusted share grew 47% year over year and 25%
compound annual growth over a 3-year period ending December 31, 2013.



Production per debt adjusted share grew by 33% year over year, and 26%
compound annual growth over a 3-year period ending December 31, 2013.
9
Operational Update:
Development Programs

10
Quarterly Production
160

143.8

27.5

31.5

35.5

41.6

40.8

71.7

69.7

71.5

2Q13

3Q13

4Q13

131.8

140
120

110.0

115.0

100

20.8

20.5

31.3

34.8

57.9

59.7

4Q12

MBOE/d

138.8

1Q13

80

24.6

60
40
20

NGL
Oil
Gas

0

 4Q13 production mix comprised of 50% liquids.
 Quarterly production increased 31% from 4Q12 to 4Q13.
 Liquids volumes grew 39% from 4Q12 to 4Q13.
11
Operated Eagle Ford
Net Production

Operational Highlights

 The Company made 20
flowing completions during
4Q13 and made 95 flowing
completions in 2013.
 At year-end 2013, SM Energy
had ~240 PDP locations, and
~200 PUD locations with an
associated ~240 MMBOE of
total proved reserves
booked.

80

74.8
66.1

68.1

51.8

18.9

21.1

15.1

5.5

8.2

41.7

38.8

42.8

2Q13

3Q13

4Q13

70

MBOE/d

 10% sequential production
growth quarter over quarter;
65% quarterly production
growth from 4Q12 to 4Q13.

60
50

45.2

40

15.2
3.9

30
20
10

24.2
7.8

6.3

26.1

30.4

4Q12

1Q13

0
NGL

Oil

Gas

 ~145,000 total net acres




~ 65,000 net acres - Briscoe Ranch
~ 15,000 net acres - Apache Ranch
~ 65,000 net acres - Galvan Ranch
12
Operated Eagle Ford Type Curve Regions
Area 6

Area 1
Area 4

Area 3A
Area 2

Area 5
Area 3B
Area 5

13
Operated Eagle Ford 2013 Activity
Area 6

Area 1
Area 4
Area 3A
Area 2
Type Curve
Area

2013 Well
Count

Net Reserve
Add (MMBOE)

1

15

2.1

2

4

2.3

3

61

47.7

4

4

1.4

5

1

0.5

6

10

4.7

Total

95

Area 3B

58.6

Area 5
2013 Wells
Prior Year Wells

14
Op. Eagle Ford CWC Efficiencies
8.0

CWC Capital ($MM)

7.0

14% Reduction

14% Reduction

6.0

5.0
4.0
3.0
2.0
1.0
0.0

2012 Avg Area 1,2,4
Well

2013 Avg Area 1,2,4
Well

2012 Avg Area 3 Well

2013 Avg Area 3 Well

15
Inventory Enhancements / Tests
 Increasing lateral length
 For the 2014 program, extending laterals on most wells out to
an average length of 6,500’ from 5,000’.
 Extended lateral lengths in Areas 1, 2, and 4 were modeled in
the type curve information in the Appendix.

 Testing completion design
 Increasing sand loading in our frac designs.
 Performance enhancement from these larger sand fracs is not
incorporated into our type curves in the Appendix.

16
2014 Activity Map
Area 6

Area 1
Area 4
Area 3A
Area 2

Area 3B

1

12

2

21
60

4

8

5

2014 Planned Activity

Well
Count

3

Area 5

Type Curve
Area

0

6

0

Total

101

17
5 Year Development Plan
Area 6

Area 1
Area 4
Area 3A
Area 2

2014
2015
2016
2017
2018

Area 3B
Area 5

18
Non-operated Eagle Ford
Operational Highlights

Net Production

 1% sequential production
growth quarter over
quarter.

MBOE/d

25
20
15
10

15.5

16.0

17.4

4Q12

1Q13

2Q13

19.8

20.0

3Q13

4Q13

5
0

 The operator ran
approximately 10 drilling
rigs during 4Q13.
 APC made 84 flowing
completions during 4Q13.
 During 4Q13, additional
compression was
commissioned, adding
additional throughput
capacity.
19
Bakken/Three Forks
MBOE/d

Net Production
18
16
14
12
10
8
6
4
2
0

Operational Highlights

 8% sequential growth quarter over
quarter; 35% quarterly production
growth 4Q12 to 4Q13.
11.9

14.9

16.1

12.2

13.7

4Q12

1Q13

2Q13

3Q13

4Q13

 The Company operated 3 rigs during
4Q13 and made 6 gross flowing
completions.

GOOSENECK
~36,000 acres


RAVEN/BEAR DEN
~43,000acres



Total Bakken/TFS net
acreage
 ~159,000
Focus area total net acreage
 ~79,000

20
Raven/Bear Den Bakken / TFS Operated 2013 Activity
Type Curve Area

Net Reserve Add
(MMBOE)

Raven/Bear Den Bakken

17/ 10

3.9

Raven/Bear Den TFS
North Dakota

Well Count
Gross/Net

13 / 8

2.6

Total

30 / 18

6.5

Raven/Bear Den

= 2013 BAKKEN WELL
= 2013 THREE FORKS WELL

21
Gooseneck TFS Operated 2013 Activity
Type Curve Area
North Dakota

Gooseneck TFS

Well Count
Gross/Net

Net Reserve Add
(MMBOE)

15 / 11

3.5

Gooseneck

22
Operated Bakken/Three Forks CWC Efficiencies

CWC Capital ($MM)

10.0
9.0

4% Reduction

8.0
4% Reduction

7.0
6.0
5.0
4.0
3.0
2.0
1.0
0.0

2012 Avg Raven/Bear
Den Well

2013 Avg Raven/Bear
Den Well

2012 Avg Gooseneck
Well

2013 Avg Gooseneck
Well

23
Inventory Enhancements / Tests
Raven / Bear Den Completion Tests
 Current design: OH packers & sleeves, 26 stages, 3.5MM# proppant, 80K Bbls of
fluid (slickwater and XL gel).
 Testing:
 Increase proppant and fluid volume (4.2MM# & 90K Bbls) on 2 wells.
 Results expected 2Q14.

Gooseneck Completion Tests
 Current design: OH Packers & Sleeves, 26 stages, 2.5MM# proppant, 47K Bbls of
fluid (slickwater and XL gel).
 Testing:
 Increase proppant volume (3MM#) on 3 wells.
 Results expected 2Q14.
 Modify drilling target interval to improve well performance.
 Results expected 3Q14.

24
East Raven Current Spacing Strategy
 Current inventory (in
Appendix) is based on:
 Up to 5 Middle Bakken wells per
spacing unit.
 4 1st Bench Three Forks wells per
spacing unit.
 This spacing results in ~530’ between
wellbores and 1,060’ between
wellbores in the same reservoir.

 Planning to test down to 880’
between wells in the same
reservoir.
 Would result in 12 wells per spacing
unit.
 Would add approximately 110 gross
wells to inventory.*

Upper Bakken Shale
Middle Bakken

1060’

Lower Bakken Shale
Three Forks 1st Bench
1060’

Three Forks 2nd Bench

*Amounts not included in inventory table in the Appendix.
25
Gooseneck Bakken Play Potential


Recent competitor results show economic
potential of Bakken in Gooseneck.
Participated in 1 non-operated well to date.



High water saturation concerns have been
mitigated by competitor activity and log
correlation to core data.



SM Energy has 25,378 net acres with
Gooseneck Bakken potential.



Gooseneck 2014 Bakken Wells

24 spacing units with potential SM Energy
operatorship.
 ~74% WI, ~19% royalty burden.



4 confirmation wells in 2014.



Possible inventory addition of 94 gross
operated wells and 20+ MMBOE of net
resource potential.*

*Amounts not included in inventory table in the Appendix.
26
Stateline Play Extends Into Montana
 Recent competitor results show economic
potential of Bakken/Three Forks in MT.
 SM Energy has 15,975 net acres in MT
Stateline (~89% HBP).
 24 spacing units with potential SM Energy
operatorship.


~52% WI, ~15% royalty burden.

 2 confirmation wells in 2014.
 Possible inventory additions*
 158 potential operated wells.


(90 Bakken, 68 Three Forks) - 79 net
wells.

 94 potential non-operated wells.


(47 Bakken, 47 Three Forks) - 4 net wells.

 Aggregate ~30MMBOE of net resource
potential.
2014 planned wells
*Amounts not included in inventory table in the Appendix.
27
Raven/Bear Den 2014 Activity
Type Curve Area

Well
Count

Raven/Bear Den Bakken

14 / 10

Raven/Bear Den TFS

18 / 13

Total

32 / 23

2014 planned activity
= 2014 BAKKEN WELL
= 2014 THREE FORKS WELL

28
Gooseneck TFS 2014 Activity
Type Curve Area
Goosneck TFS

Well
Count
13 / 8

Gooseneck

2014 planned activity
= 2014 THREE FORKS WELL

29
Operational Update:
New Ventures

30
Powder River Basin
WY

 SM Energy currently has ~140,000 net acres
in the Powder River Basin (~100,000 net
acres in the Frontier).
 Currently running 1 drilling rig developing
Frontier. 2nd rig anticipated early 2Q14.

Loco (Frontier)
30 Day IP: 1,408 BOE/d

 Completing 3rd operated Frontier well in
late 1Q14.

 2014 budget plan – Drill 10 Frontier drill
wells and make 8 completions.
 Currently the Company has 16 approved
permits in hand.

 SM Energy estimates 355 gross/148 net
Frontier locations and 264 gross/144 net
Shannon/Sussex locations.
 Aggregate 215+ MMBOE net total resource
potential.

Bridger (Shannon)
30 day IP: 499 BOE/d
Dandy (Frontier)
30 day IP: 927 BOE/d

Op PDP Hz
Op 2014 Hz

31
Permian Region
MBOE/d

Net Production
8
7
6
5
4
3
2
1
0

5.5

5.3

4Q12

1Q13

Operational Highlights

6.6

6.8

7.3

2Q13

3Q13

4Q13

 7% sequential
production growth
quarter over quarter;
33% quarterly
production growth from
4Q12 to 4Q13.
 On its Permian Shales
program, SM Energy
operated 1-2 drilling rigs
during 4Q13 and made 3
flowing completions.
32
Midland Basin Focus Map
Midland Basin
Buffalo
~47,500 Net acres

Sweetie Peck
~13,500 Net acres

33
Sweetie Peck – Horiz Well Performance
Target
Interval

Lateral
Length

Stages

Peak 30-Day
IP (BOE/d)

% Oil

Proppant

Lift
Mechanism

Dorcus 3035 H

Wolfcamp B

4,960

25

1,226

82

White Sand

ESP

Britain 3133H

Wolfcamp B

4,960

25

981

81

RCP

Gas Lift

CVX 4134 H

Wolfcamp B

4,932

25

950

76

LWC

ESP

Well Name

34
Sweetie Peck Potential
Wolfcamp ‘B’ Development
Wolfcamp B

Location
Count

Producing

3

2014 planned completions

14

Add’l Locations

79

Total Potential Locations

96*

Additional Potential

 Wolfcamp ‘D’ / Cline: ~50
wells (Test in 4Q14)
 Lower Spraberry: ~105
wells
* 96 wells assumes 50’ clearance from vertical
wells and 880’ spacing.

Producing
2014 planned wells
Add’l Locations
35
Geology
Sweetie Peck to Buffalo

Buffalo

Sweetie
Peck

36
Buffalo Program
Well Name
Tatonka 1H

Target
Interval

Lateral
Length

Stages

Peak 30-Day IP
(BOE/d)

% Oil

Proppant

Lift
Mechanism

Wolfcamp B

5,560

28

376

89

LWC

ESP

2014 Program

 Continue production test on
Tatonka 1H.
SM-Energy
Tatonka #1
Peak 7-Day rate 549 BOE/d

Diamondback
UL 4-III #1H
24-hr IP rate: 613 BOE/d
WC B

 Drill and complete a
Wolfcamp ‘D’ test in 2Q14.

W&T Offshore
Chablis #5H
24-hr IP rate: 530 BOE/d
WC A

37
Midland Basin Wolfcamp B Wells
1,800
1,600

30 Day IP (BOE)

1,400
Dorcus 3035H
1,200
Britain 3133H

1,000

CVX 4134H

800
600
Tatonka #1H

400
200
3000




4000

5000

6000

7000

8000

9000

Lateral Length (ft)

10000

11000

12000

SM Energy wells, in blue, represent a Peak 30 day average.
Graph contains allocated month production figures from IHS for non SM wells.

38
SM Energy East Texas Prospect Areas
Total Net Acreage: ~215,000
Deep Pines Central

 Three Geologic Concepts

~91,000 Net acres

Deep Pines West
~90,000 Net acres

Independence

Deep Pines East

~26,000 Net acres

~8,500 Net acres

 Eagle Ford Resource Play (East
Texas) – Extension of the South
Texas Lower Eagle Ford Play
northeast of the San Marcos
Arch.

 Austin Chalk Resource Play –
Application of modern
unconventional completion
techniques in areas where
Austin Chalk matrix is
hydrocarbon saturated but
weakly naturally fractured.
 Woodbine Sandstone Play –
Hydrocarbon charged, overpressured marine sandstones.

39
Woodbine Trap Model
Normally Pressured

Over-Pressured

Hydrocarbon-Saturated
Shaley Sandstones
(Woodbine Rim Play)

Austin Chalk

Unconventional Trap

Tight, HydrocarbonSaturated Shaley
Sandstones
(Reservoir & Seal)

Conventional Woodbine
Hydrocarbon Traps

Conventional Trap

Woodbine
Sandstones

Porous,
Permeable, Wet
Sandstones

SM Target
Eagle Ford Shale
(Hydrocarbon Source)

Buda Limestone

40
SM Energy East Texas Prospect Areas
Target
Interval

Effective
Lateral Length

Stages

Fluid Volume
(Bbl/Stage)

7-Day IP
(BOE/d)

%Oil

BTU
Gas

FCP (PSI)

Horizon 2H

Woodbine

2,500

11

7,775

873

41

1,278

1,540

Brollier 1H

Eagle Ford

4,450

17

6,500

1,474

6

1,196

6,110

Well Name

Horizon 2H

Brollier 1H

41
2014 East Texas Program
 Drill additional test wells in each of the four prospect areas
to delineate and high-grade acreage position.
 SM Energy plans to drill eight additional test wells,
primarily in the first half of 2014.
Well

Target

Matt Dillon

Woodbine
Woodbine

2Q14

Doc

Woodbine

Woodbine

Austin
Chalk

Est. Frac Date

2Q14

Ben

Target

Cameron
Heirs

1Q14

Little Joe

Well

Est. Frac Date

3Q14

3Q14

Well
Blackstone
Page *

12H

Target
Eagle Ford

Austin
Chalk

2Q14

Walter
Johnson

Well

Target

Est. Frac Date

Woodbine

2Q14

Est. Frac Date
3Q14

* Non-operated
42
Financial Update

43
Financial Position
TOTAL BOOK
CAPITALIZATION
(in millions)

 At December 31, 2013,
the Company’s net debt
to trailing EBITDAX was
0.9 and net debt to book
capitalization was 45%.

$3,500

$3,000
$2,500

$1,607

$2,000
$1,500

$1,000
$500
$0

$500
$400
$350
$0
$350
December 31, 2013

 Current revolver
commitment is $1.3
billion with borrowing
base of $2.2 billion.

Revolving Credit Facility

Senior Notes due 2019

Senior Notes due 2021

Senior Notes due 2023

Senior Notes due 2024

Stockholders’ Equity

44
Financial Position
Debt Maturities
(in millions)
$2,500
$2,000
$1,500
$1,000
$500
$0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Revolving Credit Facility

Senior Notes due 2019

Senior Notes due 2023

Senior Notes due 2024

Senior Notes due 2021

45
Debt to TTM EBITDAX
5.0x
4.5x
4.0x
3.5x
3.0x
2.5x
2.0x
1.5x
1.0x
0.5x
0.0x

Average: 2.4x

1.1

1.2

SM @
12/31/13

SM @
9/30/13

 SM Energy’s debt to trailing twelve-month EBITDAX is below
its peer average of 2.4x.
Note: 12/31/13 SM TTM EBITDAX is calculated by Company per Bloomberg definition; 9/30/13 TTM EBITDAX as calculated by Bloomberg as of 9/30/13. Balance sheet
data for peers sourced from Bloomberg as of 9/30/2013. Peer Group includes BBG, CLR, COG, CRK, CXO, DNR, EGN, FST, LPI, NFX, QEP, RRC, WLL, XCO, XEC.

46
EBITDAX Per Debt Adjusted Share
 EBITDAX per debt adjusted share increased by 44% year over
year, and compound annual growth of 22% over a 3-year period
ending December 31, 2013.

EBITDAX Per Debt Adjusted Share

$/ D.A. Sahre

$20.00
$15.00
$10.00
$5.00

$18.35
$7.81

$10.21

$13.66

$12.72

2011

2012

$0.00
2009

2010

2013
47
Key Takeaways
 Solid execution on
development programs and
advancement of new venture
plays in 2013.
 Strong year over year growth
on debt-adjusted per share
metrics.
 Proved Reserves increased 47%.
 Production increased 33%.
 EBITDAX increased 44%.

 Compelling plan for 2014.
 Optimization of development programs.
 Test new ventures.

48
Appendix

49
2014 Capital Budget
$65

($ in millions)

$200

Development
New Ventures
Non Drilling

2014 capital budget
of ~$1.9 billion

Other $60

$1,660

 Focused EFS and
Bakken programs
account for 75% of
development budget.
 Over 75% of
development capital
is allocated to
projects operated by
SM Energy.

East Texas
$55

PRB $140
Operated
Eagle
Ford $650

NonOperated
Eagle
Ford $250

Permian
Shales
$155
Bakken /
Three
Forks $350

50
Condensate Update
South Texas & Gulf Coast
% Oil Realization to LLS
$50

90%

$45

80%
70%

81%

85%

88%

86%

86%

$35

60%
50%

$40

$30

$21.33

$25

$19.64

40%

$20

30%

$15

$10.63

20%

$4.18

10%

$3.58

0%

$10

$5
$0

4Q12

1Q13

2Q13

3Q13

4Q13

LLS Premium to WTI (Blue line)

SM Oil Realization % of LLS

100%

 Substantially all of SM
Energy’s Eagle Ford
condensate trades off of an
LLS benchmark.
 The Company’s condensate
realization has remained
stable as a percentage of the
LLS benchmark.
 SM Energy has approximately
10,0000 Bbls/d of firm
condensate sales contracts
utilizing a mixture of fixed
and floating gravity
differentials.

51
4Q13 Regional Realizations
Benchmark
NYMEX WTI OIL (Bbl)
Hart Composite NGL (Bbl)
NYMEX Henry Hub Gas (MMBTU)

$
$
$

Production Volumes
Oil (MBbls)
Gas (MMcf)
NGL (MBbls)
MBOE
Revenue (in thousands)
Oil
Gas
NGL
Total
Expenses
LOE
Transportation
Production Taxes
Per Unit Metrics:
Realized Oil/Bbl
% of Benchmark – WTI
Realized Gas/Mcf
% of Benchmark - NYMEX HH
Realized NGL/Bbl
% of Benchmark – HART
Realized BOE
LOE/BOE
Transportation/BOE
Production Tax - % of Total Revenue
* Totals may not sum due to rounding.

97.41
43.13
3.82
STGC
1,449
27,442
2,813
8,836

$

Rockies
1,699
1,708
5
1,989

$

$

125,710
101,878
108,718
336,306

$
$
$

19,319
71,299
6,518

$
$
$
$
$
$

Mid-Con
113
9,285
75
1,735

$

$

142,958
10,523
282
153,763

$
$
$

20,417
1,558
15,518

86.74
89 %
3.71
97 %
38.64
90 %
38.06

$

2.19
8.07
1.9 %

$
$

$
$
$

Permian
493
1,064
0
671

$

$

9,895
37,268
2,789
49,953

$
$
$

84.15
86 %
6.16
161 %
56.42
131 %
77.32

$

10.27
0.78
10.1 %

$
$

$
$
$

SM Total
3,756
39,499
2,894
13,233

$

$

46,070
7,391
8
53,468

$

324,810
157,060
111,798
593,667

8,354
2,163
1,401

$
$
$

12,886
32
3,108

$
$
$

61,152
75,052
26,550

87.77
90 %
4.01
105 %
37.08
86 %
28.78

$

4.81
1.25
2.8 %

$
$

$
$
$

93.42
96 %
6.95
182 %
32.09
74 %
79.73

$

19.21
0.05
5.8 %

$
$

$
$
$

86.48
89 %
3.98
104 %
38.63
90 %
44.86
4.62
5.67
4.5 %

52
BAKKEN/THREE FORKS OPERATED RAVEN/BEAR DEN

DAILY EQUIVALENT
PRODUCTION (BOEPD)

Type Curve (1st 24 Months)
Oil Type
Curve

1,000

b factor

Di
(%)

Dt (%)

671

1.4

80

8

Three Forks

1,200

30 Day IP
(Bopd)

Bakken

1,400

542

1.5

80

8

800

BKN TYPE CURVE

600

TFS TYPE CURVE

400

200
0
1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MONTHS

Gross EURs

IRR Sensitivity

Operating Costs
Bakken

4.90 5.60

100%

11

80%

438

375

NGL (MBbl)

-

-

Gas (MMcf)*

543

416

Ownership

Total (MBOE)

529

444

Avg. Working Interest

~ 55%

Avg. Royalty Burden

~ 17%

Gross Capital Costs/ Well ($MM)
Total Drill & Case

$3.5

Total Complete

$5.5

Total Capital

$9.0

*Gas EUR values are net of fuel usage (10%)

Production Tax (%)

% IRR

Oil (MBbl)

Three Forks

Op Costs ($/BOE)

THREE FORKS

60%
40%
20%

Differentials

0%

Oil (% of WTI)
Gas (% of HENRY HUB)

156%

$80

92%

NGL (% of WTI)

BAKKEN

-

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil
•
•

Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude
oil price.
Economics include shrink for field usage

53
THREE FORKS OPERATED GOOSENECK
DAILY EQUIVALENT
PRODUCTION (BOEPD)

Type Curve (1st 24 Months)
900
800

Oil Type
Curve

30 Day Max
IP (Bopd)

b
factor

Di
(%)

Dt
(%)

700

Three Forks

324

1.4

63

8

600
500
400
300
200
100
0
1

2

3

Gross EURs
Oil (MBbl)

4

5

6

7

8

9

10

11

12 13 14
MONTHS

Operating Costs
368

Op Costs ($/BOE)
Production Tax (%)

Gas (MMcf)*

172

Ownership

Total (MBOE)

397

Avg. Working Interest

~ 67%

Avg. Royalty Burden

~ 19%

17

18

19

20

Total Drill & Case

$2.8

23

24

Total Complete

$3.7

Oil (% of WTI)

% IRR

20%

89%

Total Capital

$6.5

Gas (% of HENRY HUB)

40%

Differentials

116%

*Gas EUR values are net of fuel usage (22%)

22

60%

Gross Capital Costs/ Well ($MM)

NGL (% of WTI)

21

80%

11

-

16

IRR Sensitivity

2.06

NGL (MBbl)

15

-

THREE FORKS

0%
$80

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil
•
•

Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil
price.
EUR values are at the wellhead, economics include shrink for field usage

54
Operated Bakken/Three Forks Resource Potential
Gooseneck
Three Forks

Raven/Bear Den
Bakken

Raven/Bear Den
Three Forks

36,207

43,185*

43,185*

EUR/well (MBOE) **

397

529

444

Spacing (ac/well)

320

320

320

DCC/well ($MM)

6.5

9.0

9.0

93 / 7 / 0

83 / 17 / 0

84 / 16 / 0

Acreage (ac)

Product Mix (O/G/NGL)

Gross/Net
Count

Net Resource
(MMBOE)

Gross/Net
Count

Net Resource
(MMBOE)

Gross/Net
Count

Net Resource
(MMBOE)

PDP

46 / 34

7.9

55 / 36

8.6

22 / 13

3.7

PUD

40 / 29

9.2

45 / 28

10.8

11 / 8

3.0

Total Proved

86 / 63

17.1

100 / 64

19.4

33 / 21

6.7

Unproved

64 / 41

12.3

55 / 32

11.0

110 / 64

20.0

Remaining Drilling Locations

104 / 70

21.5

100 / 60

21.8

121 / 72

23.0

* Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent.
** Gas EUR values are net of fuel usage

55
Non-Operated Bakken/Three Forks Resource Potential
Gooseneck
Three Forks

Raven/Bear Den
Bakken

Raven/Bear Den
Three Forks

36,207

43,185*

43,185*

EUR/well (MBOE) **

367

529

444

Spacing (ac/well)

320

320

320

DCC/well ($MM)

6.5

9.0

9.0

93 / 7 / 0

83 / 17 / 0

84 / 16 / 0

Acreage (ac)

Product Mix (O/G/NGL)

Gross/Net
Count

Net Resource
(MMBOE)

Gross/Net
Count

Net Resource
(MMBOE)

Gross/Net
Count

Net Resource
(MMBOE)

PDP

4 / 0.5

0.1

76 / 14

3.5

36 / 5

1.4

PUD

0/0

0.0

56 / 12

5.0

16 / 2

0.9

Total Proved

4 / 0.5

0.1

132 / 26

8.5

52 / 7

2.3

Unproved

31 / 5

1.1

223 / 20

7.8

297 / 38

12.7

Remaining Drilling Locations

31 / 5

1.1

279 / 32

12.8

313 / 40

13.6

* Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent.
** Gas EUR values are net of fuel usage

56
Operated Eagle Ford Type Curve Regions
Area 6

Area 1
Area 4

Area 3A
Area 2

Area 5
Area 3B
Area 5

57
OPERATED EAGLE FORD AREA 1
DAILY EQUIVALENT
PRODUCTION (BOEPD)

Type Curve (1st 24 Months)
800
700

Gas Type
Curve

30 Day IP
(Mcfpd)

b factor

Di
(%)

Dt
(%)

600

AREA 1

1,423

1.5

69

10

500

6,500' Lateral

400
300

5,000' Lateral

200
100
0
2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

* All values based on 6,500’ lateral.
Gross EURs

MONTHS
Operating Costs

Oil (MBbl)

106

Op Costs ($/BOE)

NGL (MBbl)

174

Production Tax (%)

Gas (MMcf)

1,164

Total (MBOE)

475

Gross Capital Costs/ Well ($MM)
Total Drill & Case

$1.6

Total Complete

$5.7

Total Capital

$7.3

IRR Sensitivity

10.60

30%

3

25%
Ownership
Avg. Working Interest

~ 97%

Avg. Royalty Burden

% IRR

1

~ 22%

20%
15%
10%
5%

Differentials
Oil (% of WTI)
Gas (% of HENRY HUB)

108%

NGL (% of WTI)

43%

0%

94%

$80

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil
•

Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude
oil price.

58
OPERATED EAGLE FORD AREA 2
Type Curve (1st 24 Months)
DAILY EQUIVALENT
PRODUCTION (BOEPD)

1,400

Gas Type
Curve

b
factor

Di
(%)

Dt
(%)

AREA 2

1,200

30 Day IP
(Mcfpd)
3,829

1.2

75

10

1,000
800

6,500' Lateral

600

5,000' Lateral

400
200
0
2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MONTHS

* All values based on 6,500’ lateral.
Gross EURs

Operating Costs

Oil (MBbl)

73

Op Costs ($/BOE)

NGL (MBbl)

228

Production Tax (%)

Gas (MMcf)

1,778

Total (MBOE)

597

Gross Capital Costs/ Well ($MM)
Total Drill & Case

$1.6

Total Complete

$6.2

Total Capital

$7.8

IRR Sensitivity

10.76

60%

2

50%

40%

Ownership
Avg. Working Interest

~ 100%

Avg. Royalty Burden

% IRR

1

~ 25%

30%
20%
10%
0%

Differentials
Oil (% of WTI)
Gas (% of HENRY HUB)

107%

NGL (% of WTI)

44%

$80

94%

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil

•

Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.

59
OPERATED EAGLE FORD – AREA 3A
DAILY EQUIVALENT
PRODUCTION (BOEPD)

Type Curve (1st 24 Months)
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0

Gas Type
Curve

2

3

Gross EURs

4

5

6

7

8

9

10

11 12 13
MONTHS

Operating Costs
115

Op Costs ($/BOE)

NGL (MBbl)

391

Production Tax (%)

Gas (MMcf)

4,564

Ownership

Total (MBOE)

1,266

Avg. Working Interest

~ 100%

Avg. Royalty Burden

10.38
2

Di
(%)

Dt
(%)

5,169

1.0

55

10

15

16

17

18

19

20

21

22

23

24

IRR Sensitivity

~ 25%

200%
150%
% IRR

Oil (MBbl)

14

b
factor

AREA 3

1

30 Day IP
(Mcfpd)

100%
50%

Gross Capital Costs/ Well ($MM)

0%

Total Drill & Case

$1.8

Differentials

Total Complete

$5.0

Oil (% of WTI)

94%

Total Capital

$6.8

Gas (% of HENRY HUB)

104%

NGL (% of WTI)

40%

$80

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil

•

Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.

60
OPERATED EAGLE FORD – AREA 3B
DAILY EQUIVALENT
PRODUCTION (BOEPD)

Type Curve (1st 24 Months)
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0

Gas Type
Curve

2

3

4

5

6

7

8

9

10

Gross EURs
Oil (MBbl)

33

NGL (MBbl)

387

Production Tax (%)

Gas (MMcf)

4,515
1,172

Avg. Working Interest

~ 100%

Avg. Royalty Burden

Dt
(%)

5,169

1.0

55

10

15

~ 25%

Total Drill & Case

$1.8

Total Complete

$5.0

Total Capital

$6.8

10.92

17

18

19

20

21

22

23

24

100%

1

80%
% IRR

Gross Capital Costs/ Well ($MM)

16

IRR Sensitivity

Ownership

Total (MBOE)

14

Di
(%)

Operating Costs
Op Costs ($/BOE)

11 12 13
MONTHS

b
factor

AREA 3

1

30 Day IP
(Mcfpd)

60%
40%
20%

Differentials

0%

Oil (% of WTI)
Gas (% of HENRY HUB)

104%

NGL (% of WTI)

40%

$80

94%

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil

•

Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.

61
OPERATED EAGLE FORD AREA 4
DAILY EQUIVALENT
PRODUCTION (BOEPD)

Type Curve (1st 24 Months)
900
800

Gas Type
Curve

30 Day IP
(Mcfpd)

b
factor

Di
(%)

Dt
(%)

700

AREA 4

1,932

1.5

68

10

600
6,500' Lateral

500
400

5,000' Lateral

300
200
100
0
1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

MONTHS
* All values based on 6,500’ lateral.
Operating Costs

Oil (MBbl)

130

Op Costs ($/BOE)

NGL (MBbl)

254

Production Tax (%)

Gas (MMcf)

1,834

Total (MBOE)

690

IRR Sensitivity

10.47

40%

2

30%

Ownership
Avg. Working Interest

~ 100%

Avg. Royalty Burden

% IRR

Gross EURs

~ 21%

Gross Capital Costs/ Well ($MM)
Total Drill & Case

$1.6

Differentials

Total Complete

$5.8

Oil (% of WTI)

94%

Total Capital

$7.4

Gas (% of HENRY HUB)

107%

NGL (% of WTI)

43%

20%
10%
0%
$80

$85

$90

$95

$100

$105

$/BBL - NYMEX Oil

•

Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.

62
Operated Eagle Ford Resource Potential
AREA 1

AREA 2

AREA 3A

AREA 3B

35,082

21,879

22,226

29,726

EUR/well (MBOE)

475

597

1,266

1,172

Spacing (ac/well)

67 - 93

134

103

103

DCC/well ($MM)

7.3

7.8

6.8

6.8

22 / 41 / 37

12 / 50 / 38

Acreage (ac)

Product Mix
(O/G/NGL)

9 / 60 / 30

3 / 64 / 33

Gross/Net
Count

Net
Resource
(MMBOE)

Gross/Net
Count

Net
Resource
(MMBOE)

Gross/Net
Count

Net
Resource
(MMBOE)

Gross/Net
Count

Net
Resource
(MMBOE)

PDP*

49 / 49

5.9

26 / 26

9.9

95 / 95

51.5

39 / 39

15.8

PUD

8/8

2.7

36 / 36

22.8

79 / 79

70.6

46 / 46

31.0

57 / 57

8.6

62 / 62

32.7

174 / 174

122.1

85 / 85

46.8

Unproved

449 / 427

170.7

101 / 101

41.2

41 / 41

64.7

204 / 204

205.0

Remaining Drilling
Locations

457 / 435

173.4

137 / 137

64.0

120 / 120

135.3

250 / 250

236

Total Proved

* Includes PDN wells

63
Operated Eagle Ford Resource Potential
AREA 4

AREA 5

AREA 6

8,268

25,124

1,560

EUR/well (MBOE)

690

931

617

Spacing (ac/well)

93

143

52

DCC/well ($MM)

7.4

7.3

7.9

19 / 44 / 37

0 / 78 / 22

35 / 35 / 30

Acreage (ac)

Product Mix
(O/G/NGL)

Gross/Net
Count

Net
Resource
(MMBOE)

Gross/Net
Count

Net
Resource
(MMBOE)

Gross/Net
Count

Net
Resource
(MMBOE)

PDP*

20 / 20

4.1

16 / 16

3.2

13 / 13

5.3

PUD

21 / 21

11.7

0/0

0.0

9/9

4.5

Total Proved

41 / 41

15.8

16 / 16

3.2

22 / 22

9.8

Unproved

48 / 48

33.9

159 / 159

130.7

8/8

4.8

Remaining Drilling
Locations

69 / 69

45.6

159 / 159

130.7

17 / 17

9.3

* Includes PDN wells

64
EBITDAX Reconciliation
EBITDAX (1)
(in thousands)
Reconciliation of net income (loss) (GAAP) to EBITDAX (non-GAAP) to net cash
provided by operating activities (GAAP):
Net income (loss) (GAAP)
Interest expense
Interest income
Income tax expense (benefit)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
Exploration (2)
Impairment of proved properties
Abandonment and Impairment of unproved properties
Stock-based compensation expense
Derivative (gain) loss
Cash settlement gain
Change in Net Profits Plan liability
Gain on divestiture activity
EBITDAX (Non-GAAP)
Interest expense
Interest income
Income tax expense (benefit)
Exploration
Exploratory dry hole expense
Amortization of debt discount and deferred financing costs
Deferred income taxes
Plugging and abandonment
Other
Changes in current assets and liabilities
Net cash provided by operating activities (GAAP)

For the Three Months Ended
December 31,
2013
2012
$6,996
($67,138)
24,541
18,368
(3)
(19)
8,755
(37,008)
202,640
204,267
20,105
15,778
110,935
170,400
5,046
37,646
6,852
8,454
11,605
(15,590)
9,347
11,461
(15,419)
(11,562)
(28,484)
(4,228)
$395,516
$298,229
($24,541)
($18,368)
3
19
(8,755)
37,008
(20,105)
(15,778)
(32)
2,310
1,476
1,077
6,936
(36,943)
(2,493)
(1,052)
(154)
(379)
(10,206)
2,260
$337,645
$268,383

(1) EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion, exploration expense, property impairments, non-cash stock
compensation expense, derivative gains and losses net of cash settlements, change in the Net Profit Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that the Company believes
affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that is presented
because the Company believes that it provides useful additional information to investors, 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 financial covenants under its credit facility based on its debt to EBITDAX ratio. In addition, 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. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by (used in) operating activities,
profitability, or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not
be comparable to similar metrics of other companies.
(2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in
the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration.

65
Adjusted Net Income Reconciliation
Reconciliation of net income (loss) (GAAP) to adjusted net income (Non-GAAP):

For the Three Months Ended
December 31,

(in thousands, except per share data)
Reported Net Income (loss) (GAAP)

2013
$

2012
6,996

$

(67,138)

Adjustments net of tax: (1)
Change in Net Profits Plan liability

(9,683)

(7,249)

Derivative (gain) loss

7,288

(9,775)

Derivative cash settlement gain

5,870

7,186

(17,888)

(2,651)

Impairment of properties

69,667

106,841

Abandonment and impairment of unproved properties

23,642

3,164

Gain on divestiture activity

Adjusted net income (Non-GAAP): (2)

$

85,892

$

30,378

Adjusted net income per diluted common share:

$

1.26

$

0.45

Diluted weighted-average common shares outstanding:

68,354

66,906

(1) For the three-month period ended December 31, 2013, adjustments are shown net of tax and are calculated using a tax rate of 37.2%, which approximates the Company's
statutory tax rate adjusted for ordinary permanent differences. For the twelve-month period ended December 31, 2013, adjustments are shown net of tax using the Company's
effective rate of 38.6%, as calculated by dividing income tax expense by income before income taxes shown on the consolidated statement of operations. For the three and
twelve-month period ended December 31, 2012, adjustments are shown net of tax and are calculated using an tax rate of 37.3%, which approximates the Company's statutory tax
rate adjusted for ordinary permanent differences.
(2) 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 losses net of cash
settlements, impairment of proved properties, abandonment and impairment of unproved 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, income 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.

66
1Q14 Guidance
1Q14

FY 2014

12.0 – 12.6

51.0 – 53.5

133 – 140

140 – 147

LOE ($/BOE)

$5.25 – $5.50

$5.25 – $5.50

Transportation ($/BOE)

$5.75 – $6.05

$5.75 – $6.05

Production taxes (% of pre-derivative oil and gas revenue)

5.0% - 5.5%

5.0% - 5.5%

G&A – Cash ($/BOE)

$2.00 – $2.20

$2.20 – $2.45

G&A – Cash NPP ($/BOE)

$0.20 – $0.35

$0.20 – $0.35

G&A – Non-cash ($/BOE)

$0.35 – $0.50

$0.30 – $0.50

G&A Total ($/BOE)

$2.55 – $3.05

$2.70 – $3.30

$15.10 – $15.90

$15.10 – $15.90

Production (MMBOE)
Average daily production (MBOE/d)

DD&A ($/BOE)
Effective income tax rate range

37.0% – 37.5%

% of income tax that is current

<3%
67
Oil Derivative Position*
Oil Swaps - NYMEX Equivalent

Bbls

Oil Swaps – WTI swap with LLS basis Differential

$/Bbl

2014
Q1
Q2
Q3
Q4
2014 Total

2,175,000
2,373,000
973,000
891,000
6,412,000

$
$
$
$

2015
Q1
Q2
Q3
Q4
2015 Total

820,000
896,000
615,000
580,000
2,911,000

$
$
$
$

1,382,000
1,322,000
2,704,000

$
$

85.19
85.19

Grand Total

425,000
425,000

Grand Total

12,027,000

96.13
94.95
95.25
95.16

2014
Q1
2014 Total

$/Bbl

89.09
88.93
89.15
89.14

2016
Q1
Q4
2016 Total

Bbls

425,000

$

100.91

*As of 2/12/14

68
Oil Derivative Position*
Oil Collars - NYMEX Equivalent
Ceiling
$/Bbl

Bbls

Floor
$/Bbl

2014
Q1
Q2
Q3
Q4
2014 Total

694,000
431,000
973,000
923,000
3,021,000

$
$
$
$

115.07
102.50
102.58
102.63

$
$
$
$

80.97
85.00
85.00
85.00

2015
Q1
Q2
Q3
Q4
2015 Total

882,000
709,000
906,000
869,000
3,366,000

$
$
$
$

99.53
94.06
91.25
92.19

$
$
$
$

85.00
85.00
85.00
85.00

Grand Total

6,387,000

*As of 2/12/14

69
Gas Derivative Position*

Natural Gas Swaps - NYMEX Equivalent

MMBTU

Natural Gas Collars - NYMEX Equivalent

$/MMBTU

2014

Ceiling
$/MMBTU

MMBTU

Floor
$/MMBTU

2014

Q1

32,266,000

$

4.24

Q1

1,540,000

$

5.59

$

4.40

Q2

23,758,000

$

4.06

Q2

4,194,000

$

5.41

$

4.51

Q3

24,541,000

$

4.10

Q3

-

Q4

22,014,000

$

4.13

2014 Total

102,579,000

2015

Q4

-

2014 Total

5,734,000

2015

Q1

17,342,000

$

4.30

Q1

2,525,000

$

4.41

$

4.11

Q2

15,985,000

$

4.06

Q2

2,297,000

$

4.44

$

4.14

Q3

14,950,000

$

4.18

Q3

2,005,000

$

4.44

$

4.14

Q4

9,667,000

$

4.18

Q4

6,176,000

$

4.45

$

4.12

2015 Total

57,944,000

2015 Total

13,003,000

Grand Total

18,737,000

2016
Q1

14,703,000

$

4.42

Q2

9,130,000

$

4.19

Q3

7,004,000

$

4.26

Q4

6,635,000

$

4.25

2016 Total

37,472,000

2017
Q1

6,299,000

$

Q2

5,974,000

$

4.31

4.30

Q3

5,712,000

$

4.30

Q4

5,445,000

$

4.43

2017 Total

23,430,000

Note: Excludes volumes that were early settled in
1Q14 to unwind trades associated with Anadarko
Basin properties sold on 12/30/13. The early
settlement of these trades will result in a cash
settlement gain of $5.6 million in 1Q14.

2018
Q1

5,203,000

$

4.43

Q2

4,997,000

$

4.43

2018 Total

10,200,000

Grand Total

231,625,000

*As of 2/12/14
70
NGL Derivative Position*
Natural Gas Liquid Swaps - Mont. Belvieu
Bbls
2014
Q1
Q2
Q3
Q4

1,429,000
1,096,000
960,000
861,000

2014 Total

4,346,000

Grand Total

$/Bbl

4,346,000

$
$
$
$

57.96
58.04
58.06
58.06

*As of 2/12/14
71

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SM Energy - 4th Quarter 2013 Earnings Call

  • 1. 4th Quarter 2013 Earnings Call and Operational Update February 19, 2014
  • 2. Forward Looking Statements - Cautionary Language Except for historical information contained herein, statements in this presentation, including information regarding the business of the Company, contain 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 2013 Annual Report on Form 10-K. 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. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In this presentation, the Company uses the terms “probable,” “possible,” “3P,” and “resources.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations (subject to other conditions). Resources are quantities of oil and gas and related substances estimated to exist in naturally occurring accumulations. SM Energy also uses the term “EUR” (estimated ultimate recovery), which is the sum of reserves remaining as of a given date and cumulative production as of that date. Estimates of probable and possible reserves included in 3P reserves and resources which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. 2
  • 3. Key Messages  SM Energy had record production for the year.  Annual avg. daily production growth of 33%.  4Q12 to 4Q13 production growth of 31%.  2013 was a strong year for proved reserves.  Proved reserves grew 46% year over year.  Drilling F&D costs decreased by 26% year over year.  Balance sheet remains strong with net Debt to TTM EBITDAX of <1x.  SM Energy stock outperformed the EPX index by 33 percentage points in 2013, ending the year up 59%. 3
  • 4. th 4 Quarter 2013 Performance Production 4Q13 Actual Performance 4Q13 Guidance Net Income 143.8 139 - 146 Total production (MMBOE) 13.23 GAAP net income of $7.0 million, or $0.10 per diluted share.  Average daily production (MBOE/d)  Adjusted net income* (non-GAAP) of $85.9 million, or $1.26 per adjusted diluted share. 12.8 - 13.5 Costs LOE ($/BOE) Transportation ($/BOE) Production taxes (% of pre-derivative oil, gas, & NGL revenue) $4.62 $5.67 G&A -- Cash ($/BOE) G&A -- Cash NPP ($/BOE) G&A -- Non-cash ($/BOE) TOTAL G&A ($/BOE) ** $3.07 $0.17 $0.39 $3.63 $2.15 - $2.35 $0.25 - $0.40 $0.45 - $0.60 $2.85 - $3.35 $15.31 $15.00 - $16.00 DD&A ($/BOE) 4.5% $4.65 - $4.90 $5.40 - $5.65 5.0% - 5.5% EBITDAX  EBITDAX* (nonGAAP) of $395.5 million. * Please see adjusted net income and EBITDAX reconciliations in the Appendix. ** 4Q13 G&A per unit expenses were higher than guidance due to performance-based bonus compensation. 4
  • 6. 2013 Proved Reserve Roll-Forward MMBOE 54% Liquids/ 46% Gas 600 500 53% Liquids/ 47% Gas 195.5 5.0 1.3 18.2 48.3 428.7 400 293.4 219.9 300 200 126.9 Proved Developed 100 Proved Undeveloped 208.9 166.5 0 Beginning Proved Reserves Adds/Infill Acquisitions Revisions Divestitures Production Ending Proved Reserves  Proved reserves increased by 46% from 2012.  Liquid volumes of proved reserves increased 49% year over year. 6
  • 7. Reserve Metrics  Drilling F&D decreased by approximately 26% in 2013 to $7.77 per BOE.  Reserve replacement in excess of 400% for the second consecutive year. F&D $/BOE $25.00 $20.00 $15.00 405% $20.64 $17.10 $12.84 $10.00 $10.44 $5.00 $7.77 $0.00 2009 2010 Drilling F&D costs, excluding revisions 2011 2012 450% 400% 350% 300% 250% 200% 150% 100% 50% 0% Reserve Replacement % Reserve Metrics 2013 Drilling reserve replacement, excluding revisions 7
  • 8. Annual Production 150 132.4 MBOE/d 125 99.7 100 75 50 25 49.8 50.2 17.3 77.5 9.6 16.7 32.5 32.8 2009 2010 38.2 28.3 17.4 22.1 26.0 45.8 54.7 2011 2012 NGL Oil Gas 68.2 0 2013  2013 average daily annual production grew ~33% from 2012.  3-year compounded annual average daily production growth of ~38%.  Liquids volumes have increased 103% since 2011, when the Company began reporting NGL volumes. 8
  • 9. Debt Adjusted Metrics BOE/D.A. Share 5.0 4.0 3.0 Proved reserves per debt adjusted share Production per debt adjusted share 0.3 2.1 0.6 0.4 0.5 2.8 0.5 0.4 0.3 2.0 1.0 0.6 0.7 5.5 3.1 3.8 0.3 0.2 BOE/D.A. Share 6.0 0.1 0.0 0.0 2009 2010 2011 2012 2013  Proved reserves per debt adjusted share grew 47% year over year and 25% compound annual growth over a 3-year period ending December 31, 2013.  Production per debt adjusted share grew by 33% year over year, and 26% compound annual growth over a 3-year period ending December 31, 2013. 9
  • 11. Quarterly Production 160 143.8 27.5 31.5 35.5 41.6 40.8 71.7 69.7 71.5 2Q13 3Q13 4Q13 131.8 140 120 110.0 115.0 100 20.8 20.5 31.3 34.8 57.9 59.7 4Q12 MBOE/d 138.8 1Q13 80 24.6 60 40 20 NGL Oil Gas 0  4Q13 production mix comprised of 50% liquids.  Quarterly production increased 31% from 4Q12 to 4Q13.  Liquids volumes grew 39% from 4Q12 to 4Q13. 11
  • 12. Operated Eagle Ford Net Production Operational Highlights  The Company made 20 flowing completions during 4Q13 and made 95 flowing completions in 2013.  At year-end 2013, SM Energy had ~240 PDP locations, and ~200 PUD locations with an associated ~240 MMBOE of total proved reserves booked. 80 74.8 66.1 68.1 51.8 18.9 21.1 15.1 5.5 8.2 41.7 38.8 42.8 2Q13 3Q13 4Q13 70 MBOE/d  10% sequential production growth quarter over quarter; 65% quarterly production growth from 4Q12 to 4Q13. 60 50 45.2 40 15.2 3.9 30 20 10 24.2 7.8 6.3 26.1 30.4 4Q12 1Q13 0 NGL Oil Gas  ~145,000 total net acres    ~ 65,000 net acres - Briscoe Ranch ~ 15,000 net acres - Apache Ranch ~ 65,000 net acres - Galvan Ranch 12
  • 13. Operated Eagle Ford Type Curve Regions Area 6 Area 1 Area 4 Area 3A Area 2 Area 5 Area 3B Area 5 13
  • 14. Operated Eagle Ford 2013 Activity Area 6 Area 1 Area 4 Area 3A Area 2 Type Curve Area 2013 Well Count Net Reserve Add (MMBOE) 1 15 2.1 2 4 2.3 3 61 47.7 4 4 1.4 5 1 0.5 6 10 4.7 Total 95 Area 3B 58.6 Area 5 2013 Wells Prior Year Wells 14
  • 15. Op. Eagle Ford CWC Efficiencies 8.0 CWC Capital ($MM) 7.0 14% Reduction 14% Reduction 6.0 5.0 4.0 3.0 2.0 1.0 0.0 2012 Avg Area 1,2,4 Well 2013 Avg Area 1,2,4 Well 2012 Avg Area 3 Well 2013 Avg Area 3 Well 15
  • 16. Inventory Enhancements / Tests  Increasing lateral length  For the 2014 program, extending laterals on most wells out to an average length of 6,500’ from 5,000’.  Extended lateral lengths in Areas 1, 2, and 4 were modeled in the type curve information in the Appendix.  Testing completion design  Increasing sand loading in our frac designs.  Performance enhancement from these larger sand fracs is not incorporated into our type curves in the Appendix. 16
  • 17. 2014 Activity Map Area 6 Area 1 Area 4 Area 3A Area 2 Area 3B 1 12 2 21 60 4 8 5 2014 Planned Activity Well Count 3 Area 5 Type Curve Area 0 6 0 Total 101 17
  • 18. 5 Year Development Plan Area 6 Area 1 Area 4 Area 3A Area 2 2014 2015 2016 2017 2018 Area 3B Area 5 18
  • 19. Non-operated Eagle Ford Operational Highlights Net Production  1% sequential production growth quarter over quarter. MBOE/d 25 20 15 10 15.5 16.0 17.4 4Q12 1Q13 2Q13 19.8 20.0 3Q13 4Q13 5 0  The operator ran approximately 10 drilling rigs during 4Q13.  APC made 84 flowing completions during 4Q13.  During 4Q13, additional compression was commissioned, adding additional throughput capacity. 19
  • 20. Bakken/Three Forks MBOE/d Net Production 18 16 14 12 10 8 6 4 2 0 Operational Highlights  8% sequential growth quarter over quarter; 35% quarterly production growth 4Q12 to 4Q13. 11.9 14.9 16.1 12.2 13.7 4Q12 1Q13 2Q13 3Q13 4Q13  The Company operated 3 rigs during 4Q13 and made 6 gross flowing completions. GOOSENECK ~36,000 acres  RAVEN/BEAR DEN ~43,000acres  Total Bakken/TFS net acreage  ~159,000 Focus area total net acreage  ~79,000 20
  • 21. Raven/Bear Den Bakken / TFS Operated 2013 Activity Type Curve Area Net Reserve Add (MMBOE) Raven/Bear Den Bakken 17/ 10 3.9 Raven/Bear Den TFS North Dakota Well Count Gross/Net 13 / 8 2.6 Total 30 / 18 6.5 Raven/Bear Den = 2013 BAKKEN WELL = 2013 THREE FORKS WELL 21
  • 22. Gooseneck TFS Operated 2013 Activity Type Curve Area North Dakota Gooseneck TFS Well Count Gross/Net Net Reserve Add (MMBOE) 15 / 11 3.5 Gooseneck 22
  • 23. Operated Bakken/Three Forks CWC Efficiencies CWC Capital ($MM) 10.0 9.0 4% Reduction 8.0 4% Reduction 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 2012 Avg Raven/Bear Den Well 2013 Avg Raven/Bear Den Well 2012 Avg Gooseneck Well 2013 Avg Gooseneck Well 23
  • 24. Inventory Enhancements / Tests Raven / Bear Den Completion Tests  Current design: OH packers & sleeves, 26 stages, 3.5MM# proppant, 80K Bbls of fluid (slickwater and XL gel).  Testing:  Increase proppant and fluid volume (4.2MM# & 90K Bbls) on 2 wells.  Results expected 2Q14. Gooseneck Completion Tests  Current design: OH Packers & Sleeves, 26 stages, 2.5MM# proppant, 47K Bbls of fluid (slickwater and XL gel).  Testing:  Increase proppant volume (3MM#) on 3 wells.  Results expected 2Q14.  Modify drilling target interval to improve well performance.  Results expected 3Q14. 24
  • 25. East Raven Current Spacing Strategy  Current inventory (in Appendix) is based on:  Up to 5 Middle Bakken wells per spacing unit.  4 1st Bench Three Forks wells per spacing unit.  This spacing results in ~530’ between wellbores and 1,060’ between wellbores in the same reservoir.  Planning to test down to 880’ between wells in the same reservoir.  Would result in 12 wells per spacing unit.  Would add approximately 110 gross wells to inventory.* Upper Bakken Shale Middle Bakken 1060’ Lower Bakken Shale Three Forks 1st Bench 1060’ Three Forks 2nd Bench *Amounts not included in inventory table in the Appendix. 25
  • 26. Gooseneck Bakken Play Potential  Recent competitor results show economic potential of Bakken in Gooseneck. Participated in 1 non-operated well to date.  High water saturation concerns have been mitigated by competitor activity and log correlation to core data.  SM Energy has 25,378 net acres with Gooseneck Bakken potential.  Gooseneck 2014 Bakken Wells 24 spacing units with potential SM Energy operatorship.  ~74% WI, ~19% royalty burden.  4 confirmation wells in 2014.  Possible inventory addition of 94 gross operated wells and 20+ MMBOE of net resource potential.* *Amounts not included in inventory table in the Appendix. 26
  • 27. Stateline Play Extends Into Montana  Recent competitor results show economic potential of Bakken/Three Forks in MT.  SM Energy has 15,975 net acres in MT Stateline (~89% HBP).  24 spacing units with potential SM Energy operatorship.  ~52% WI, ~15% royalty burden.  2 confirmation wells in 2014.  Possible inventory additions*  158 potential operated wells.  (90 Bakken, 68 Three Forks) - 79 net wells.  94 potential non-operated wells.  (47 Bakken, 47 Three Forks) - 4 net wells.  Aggregate ~30MMBOE of net resource potential. 2014 planned wells *Amounts not included in inventory table in the Appendix. 27
  • 28. Raven/Bear Den 2014 Activity Type Curve Area Well Count Raven/Bear Den Bakken 14 / 10 Raven/Bear Den TFS 18 / 13 Total 32 / 23 2014 planned activity = 2014 BAKKEN WELL = 2014 THREE FORKS WELL 28
  • 29. Gooseneck TFS 2014 Activity Type Curve Area Goosneck TFS Well Count 13 / 8 Gooseneck 2014 planned activity = 2014 THREE FORKS WELL 29
  • 31. Powder River Basin WY  SM Energy currently has ~140,000 net acres in the Powder River Basin (~100,000 net acres in the Frontier).  Currently running 1 drilling rig developing Frontier. 2nd rig anticipated early 2Q14. Loco (Frontier) 30 Day IP: 1,408 BOE/d  Completing 3rd operated Frontier well in late 1Q14.  2014 budget plan – Drill 10 Frontier drill wells and make 8 completions.  Currently the Company has 16 approved permits in hand.  SM Energy estimates 355 gross/148 net Frontier locations and 264 gross/144 net Shannon/Sussex locations.  Aggregate 215+ MMBOE net total resource potential. Bridger (Shannon) 30 day IP: 499 BOE/d Dandy (Frontier) 30 day IP: 927 BOE/d Op PDP Hz Op 2014 Hz 31
  • 32. Permian Region MBOE/d Net Production 8 7 6 5 4 3 2 1 0 5.5 5.3 4Q12 1Q13 Operational Highlights 6.6 6.8 7.3 2Q13 3Q13 4Q13  7% sequential production growth quarter over quarter; 33% quarterly production growth from 4Q12 to 4Q13.  On its Permian Shales program, SM Energy operated 1-2 drilling rigs during 4Q13 and made 3 flowing completions. 32
  • 33. Midland Basin Focus Map Midland Basin Buffalo ~47,500 Net acres Sweetie Peck ~13,500 Net acres 33
  • 34. Sweetie Peck – Horiz Well Performance Target Interval Lateral Length Stages Peak 30-Day IP (BOE/d) % Oil Proppant Lift Mechanism Dorcus 3035 H Wolfcamp B 4,960 25 1,226 82 White Sand ESP Britain 3133H Wolfcamp B 4,960 25 981 81 RCP Gas Lift CVX 4134 H Wolfcamp B 4,932 25 950 76 LWC ESP Well Name 34
  • 35. Sweetie Peck Potential Wolfcamp ‘B’ Development Wolfcamp B Location Count Producing 3 2014 planned completions 14 Add’l Locations 79 Total Potential Locations 96* Additional Potential  Wolfcamp ‘D’ / Cline: ~50 wells (Test in 4Q14)  Lower Spraberry: ~105 wells * 96 wells assumes 50’ clearance from vertical wells and 880’ spacing. Producing 2014 planned wells Add’l Locations 35
  • 36. Geology Sweetie Peck to Buffalo Buffalo Sweetie Peck 36
  • 37. Buffalo Program Well Name Tatonka 1H Target Interval Lateral Length Stages Peak 30-Day IP (BOE/d) % Oil Proppant Lift Mechanism Wolfcamp B 5,560 28 376 89 LWC ESP 2014 Program  Continue production test on Tatonka 1H. SM-Energy Tatonka #1 Peak 7-Day rate 549 BOE/d Diamondback UL 4-III #1H 24-hr IP rate: 613 BOE/d WC B  Drill and complete a Wolfcamp ‘D’ test in 2Q14. W&T Offshore Chablis #5H 24-hr IP rate: 530 BOE/d WC A 37
  • 38. Midland Basin Wolfcamp B Wells 1,800 1,600 30 Day IP (BOE) 1,400 Dorcus 3035H 1,200 Britain 3133H 1,000 CVX 4134H 800 600 Tatonka #1H 400 200 3000   4000 5000 6000 7000 8000 9000 Lateral Length (ft) 10000 11000 12000 SM Energy wells, in blue, represent a Peak 30 day average. Graph contains allocated month production figures from IHS for non SM wells. 38
  • 39. SM Energy East Texas Prospect Areas Total Net Acreage: ~215,000 Deep Pines Central  Three Geologic Concepts ~91,000 Net acres Deep Pines West ~90,000 Net acres Independence Deep Pines East ~26,000 Net acres ~8,500 Net acres  Eagle Ford Resource Play (East Texas) – Extension of the South Texas Lower Eagle Ford Play northeast of the San Marcos Arch.  Austin Chalk Resource Play – Application of modern unconventional completion techniques in areas where Austin Chalk matrix is hydrocarbon saturated but weakly naturally fractured.  Woodbine Sandstone Play – Hydrocarbon charged, overpressured marine sandstones. 39
  • 40. Woodbine Trap Model Normally Pressured Over-Pressured Hydrocarbon-Saturated Shaley Sandstones (Woodbine Rim Play) Austin Chalk Unconventional Trap Tight, HydrocarbonSaturated Shaley Sandstones (Reservoir & Seal) Conventional Woodbine Hydrocarbon Traps Conventional Trap Woodbine Sandstones Porous, Permeable, Wet Sandstones SM Target Eagle Ford Shale (Hydrocarbon Source) Buda Limestone 40
  • 41. SM Energy East Texas Prospect Areas Target Interval Effective Lateral Length Stages Fluid Volume (Bbl/Stage) 7-Day IP (BOE/d) %Oil BTU Gas FCP (PSI) Horizon 2H Woodbine 2,500 11 7,775 873 41 1,278 1,540 Brollier 1H Eagle Ford 4,450 17 6,500 1,474 6 1,196 6,110 Well Name Horizon 2H Brollier 1H 41
  • 42. 2014 East Texas Program  Drill additional test wells in each of the four prospect areas to delineate and high-grade acreage position.  SM Energy plans to drill eight additional test wells, primarily in the first half of 2014. Well Target Matt Dillon Woodbine Woodbine 2Q14 Doc Woodbine Woodbine Austin Chalk Est. Frac Date 2Q14 Ben Target Cameron Heirs 1Q14 Little Joe Well Est. Frac Date 3Q14 3Q14 Well Blackstone Page * 12H Target Eagle Ford Austin Chalk 2Q14 Walter Johnson Well Target Est. Frac Date Woodbine 2Q14 Est. Frac Date 3Q14 * Non-operated 42
  • 44. Financial Position TOTAL BOOK CAPITALIZATION (in millions)  At December 31, 2013, the Company’s net debt to trailing EBITDAX was 0.9 and net debt to book capitalization was 45%. $3,500 $3,000 $2,500 $1,607 $2,000 $1,500 $1,000 $500 $0 $500 $400 $350 $0 $350 December 31, 2013  Current revolver commitment is $1.3 billion with borrowing base of $2.2 billion. Revolving Credit Facility Senior Notes due 2019 Senior Notes due 2021 Senior Notes due 2023 Senior Notes due 2024 Stockholders’ Equity 44
  • 45. Financial Position Debt Maturities (in millions) $2,500 $2,000 $1,500 $1,000 $500 $0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Revolving Credit Facility Senior Notes due 2019 Senior Notes due 2023 Senior Notes due 2024 Senior Notes due 2021 45
  • 46. Debt to TTM EBITDAX 5.0x 4.5x 4.0x 3.5x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x Average: 2.4x 1.1 1.2 SM @ 12/31/13 SM @ 9/30/13  SM Energy’s debt to trailing twelve-month EBITDAX is below its peer average of 2.4x. Note: 12/31/13 SM TTM EBITDAX is calculated by Company per Bloomberg definition; 9/30/13 TTM EBITDAX as calculated by Bloomberg as of 9/30/13. Balance sheet data for peers sourced from Bloomberg as of 9/30/2013. Peer Group includes BBG, CLR, COG, CRK, CXO, DNR, EGN, FST, LPI, NFX, QEP, RRC, WLL, XCO, XEC. 46
  • 47. EBITDAX Per Debt Adjusted Share  EBITDAX per debt adjusted share increased by 44% year over year, and compound annual growth of 22% over a 3-year period ending December 31, 2013. EBITDAX Per Debt Adjusted Share $/ D.A. Sahre $20.00 $15.00 $10.00 $5.00 $18.35 $7.81 $10.21 $13.66 $12.72 2011 2012 $0.00 2009 2010 2013 47
  • 48. Key Takeaways  Solid execution on development programs and advancement of new venture plays in 2013.  Strong year over year growth on debt-adjusted per share metrics.  Proved Reserves increased 47%.  Production increased 33%.  EBITDAX increased 44%.  Compelling plan for 2014.  Optimization of development programs.  Test new ventures. 48
  • 50. 2014 Capital Budget $65 ($ in millions) $200 Development New Ventures Non Drilling 2014 capital budget of ~$1.9 billion Other $60 $1,660  Focused EFS and Bakken programs account for 75% of development budget.  Over 75% of development capital is allocated to projects operated by SM Energy. East Texas $55 PRB $140 Operated Eagle Ford $650 NonOperated Eagle Ford $250 Permian Shales $155 Bakken / Three Forks $350 50
  • 51. Condensate Update South Texas & Gulf Coast % Oil Realization to LLS $50 90% $45 80% 70% 81% 85% 88% 86% 86% $35 60% 50% $40 $30 $21.33 $25 $19.64 40% $20 30% $15 $10.63 20% $4.18 10% $3.58 0% $10 $5 $0 4Q12 1Q13 2Q13 3Q13 4Q13 LLS Premium to WTI (Blue line) SM Oil Realization % of LLS 100%  Substantially all of SM Energy’s Eagle Ford condensate trades off of an LLS benchmark.  The Company’s condensate realization has remained stable as a percentage of the LLS benchmark.  SM Energy has approximately 10,0000 Bbls/d of firm condensate sales contracts utilizing a mixture of fixed and floating gravity differentials. 51
  • 52. 4Q13 Regional Realizations Benchmark NYMEX WTI OIL (Bbl) Hart Composite NGL (Bbl) NYMEX Henry Hub Gas (MMBTU) $ $ $ Production Volumes Oil (MBbls) Gas (MMcf) NGL (MBbls) MBOE Revenue (in thousands) Oil Gas NGL Total Expenses LOE Transportation Production Taxes Per Unit Metrics: Realized Oil/Bbl % of Benchmark – WTI Realized Gas/Mcf % of Benchmark - NYMEX HH Realized NGL/Bbl % of Benchmark – HART Realized BOE LOE/BOE Transportation/BOE Production Tax - % of Total Revenue * Totals may not sum due to rounding. 97.41 43.13 3.82 STGC 1,449 27,442 2,813 8,836 $ Rockies 1,699 1,708 5 1,989 $ $ 125,710 101,878 108,718 336,306 $ $ $ 19,319 71,299 6,518 $ $ $ $ $ $ Mid-Con 113 9,285 75 1,735 $ $ 142,958 10,523 282 153,763 $ $ $ 20,417 1,558 15,518 86.74 89 % 3.71 97 % 38.64 90 % 38.06 $ 2.19 8.07 1.9 % $ $ $ $ $ Permian 493 1,064 0 671 $ $ 9,895 37,268 2,789 49,953 $ $ $ 84.15 86 % 6.16 161 % 56.42 131 % 77.32 $ 10.27 0.78 10.1 % $ $ $ $ $ SM Total 3,756 39,499 2,894 13,233 $ $ 46,070 7,391 8 53,468 $ 324,810 157,060 111,798 593,667 8,354 2,163 1,401 $ $ $ 12,886 32 3,108 $ $ $ 61,152 75,052 26,550 87.77 90 % 4.01 105 % 37.08 86 % 28.78 $ 4.81 1.25 2.8 % $ $ $ $ $ 93.42 96 % 6.95 182 % 32.09 74 % 79.73 $ 19.21 0.05 5.8 % $ $ $ $ $ 86.48 89 % 3.98 104 % 38.63 90 % 44.86 4.62 5.67 4.5 % 52
  • 53. BAKKEN/THREE FORKS OPERATED RAVEN/BEAR DEN DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) Oil Type Curve 1,000 b factor Di (%) Dt (%) 671 1.4 80 8 Three Forks 1,200 30 Day IP (Bopd) Bakken 1,400 542 1.5 80 8 800 BKN TYPE CURVE 600 TFS TYPE CURVE 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MONTHS Gross EURs IRR Sensitivity Operating Costs Bakken 4.90 5.60 100% 11 80% 438 375 NGL (MBbl) - - Gas (MMcf)* 543 416 Ownership Total (MBOE) 529 444 Avg. Working Interest ~ 55% Avg. Royalty Burden ~ 17% Gross Capital Costs/ Well ($MM) Total Drill & Case $3.5 Total Complete $5.5 Total Capital $9.0 *Gas EUR values are net of fuel usage (10%) Production Tax (%) % IRR Oil (MBbl) Three Forks Op Costs ($/BOE) THREE FORKS 60% 40% 20% Differentials 0% Oil (% of WTI) Gas (% of HENRY HUB) 156% $80 92% NGL (% of WTI) BAKKEN - $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. Economics include shrink for field usage 53
  • 54. THREE FORKS OPERATED GOOSENECK DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 900 800 Oil Type Curve 30 Day Max IP (Bopd) b factor Di (%) Dt (%) 700 Three Forks 324 1.4 63 8 600 500 400 300 200 100 0 1 2 3 Gross EURs Oil (MBbl) 4 5 6 7 8 9 10 11 12 13 14 MONTHS Operating Costs 368 Op Costs ($/BOE) Production Tax (%) Gas (MMcf)* 172 Ownership Total (MBOE) 397 Avg. Working Interest ~ 67% Avg. Royalty Burden ~ 19% 17 18 19 20 Total Drill & Case $2.8 23 24 Total Complete $3.7 Oil (% of WTI) % IRR 20% 89% Total Capital $6.5 Gas (% of HENRY HUB) 40% Differentials 116% *Gas EUR values are net of fuel usage (22%) 22 60% Gross Capital Costs/ Well ($MM) NGL (% of WTI) 21 80% 11 - 16 IRR Sensitivity 2.06 NGL (MBbl) 15 - THREE FORKS 0% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. EUR values are at the wellhead, economics include shrink for field usage 54
  • 55. Operated Bakken/Three Forks Resource Potential Gooseneck Three Forks Raven/Bear Den Bakken Raven/Bear Den Three Forks 36,207 43,185* 43,185* EUR/well (MBOE) ** 397 529 444 Spacing (ac/well) 320 320 320 DCC/well ($MM) 6.5 9.0 9.0 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0 Acreage (ac) Product Mix (O/G/NGL) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP 46 / 34 7.9 55 / 36 8.6 22 / 13 3.7 PUD 40 / 29 9.2 45 / 28 10.8 11 / 8 3.0 Total Proved 86 / 63 17.1 100 / 64 19.4 33 / 21 6.7 Unproved 64 / 41 12.3 55 / 32 11.0 110 / 64 20.0 Remaining Drilling Locations 104 / 70 21.5 100 / 60 21.8 121 / 72 23.0 * Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent. ** Gas EUR values are net of fuel usage 55
  • 56. Non-Operated Bakken/Three Forks Resource Potential Gooseneck Three Forks Raven/Bear Den Bakken Raven/Bear Den Three Forks 36,207 43,185* 43,185* EUR/well (MBOE) ** 367 529 444 Spacing (ac/well) 320 320 320 DCC/well ($MM) 6.5 9.0 9.0 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0 Acreage (ac) Product Mix (O/G/NGL) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP 4 / 0.5 0.1 76 / 14 3.5 36 / 5 1.4 PUD 0/0 0.0 56 / 12 5.0 16 / 2 0.9 Total Proved 4 / 0.5 0.1 132 / 26 8.5 52 / 7 2.3 Unproved 31 / 5 1.1 223 / 20 7.8 297 / 38 12.7 Remaining Drilling Locations 31 / 5 1.1 279 / 32 12.8 313 / 40 13.6 * Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent. ** Gas EUR values are net of fuel usage 56
  • 57. Operated Eagle Ford Type Curve Regions Area 6 Area 1 Area 4 Area 3A Area 2 Area 5 Area 3B Area 5 57
  • 58. OPERATED EAGLE FORD AREA 1 DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 800 700 Gas Type Curve 30 Day IP (Mcfpd) b factor Di (%) Dt (%) 600 AREA 1 1,423 1.5 69 10 500 6,500' Lateral 400 300 5,000' Lateral 200 100 0 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 * All values based on 6,500’ lateral. Gross EURs MONTHS Operating Costs Oil (MBbl) 106 Op Costs ($/BOE) NGL (MBbl) 174 Production Tax (%) Gas (MMcf) 1,164 Total (MBOE) 475 Gross Capital Costs/ Well ($MM) Total Drill & Case $1.6 Total Complete $5.7 Total Capital $7.3 IRR Sensitivity 10.60 30% 3 25% Ownership Avg. Working Interest ~ 97% Avg. Royalty Burden % IRR 1 ~ 22% 20% 15% 10% 5% Differentials Oil (% of WTI) Gas (% of HENRY HUB) 108% NGL (% of WTI) 43% 0% 94% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 58
  • 59. OPERATED EAGLE FORD AREA 2 Type Curve (1st 24 Months) DAILY EQUIVALENT PRODUCTION (BOEPD) 1,400 Gas Type Curve b factor Di (%) Dt (%) AREA 2 1,200 30 Day IP (Mcfpd) 3,829 1.2 75 10 1,000 800 6,500' Lateral 600 5,000' Lateral 400 200 0 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MONTHS * All values based on 6,500’ lateral. Gross EURs Operating Costs Oil (MBbl) 73 Op Costs ($/BOE) NGL (MBbl) 228 Production Tax (%) Gas (MMcf) 1,778 Total (MBOE) 597 Gross Capital Costs/ Well ($MM) Total Drill & Case $1.6 Total Complete $6.2 Total Capital $7.8 IRR Sensitivity 10.76 60% 2 50% 40% Ownership Avg. Working Interest ~ 100% Avg. Royalty Burden % IRR 1 ~ 25% 30% 20% 10% 0% Differentials Oil (% of WTI) Gas (% of HENRY HUB) 107% NGL (% of WTI) 44% $80 94% $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 59
  • 60. OPERATED EAGLE FORD – AREA 3A DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Gas Type Curve 2 3 Gross EURs 4 5 6 7 8 9 10 11 12 13 MONTHS Operating Costs 115 Op Costs ($/BOE) NGL (MBbl) 391 Production Tax (%) Gas (MMcf) 4,564 Ownership Total (MBOE) 1,266 Avg. Working Interest ~ 100% Avg. Royalty Burden 10.38 2 Di (%) Dt (%) 5,169 1.0 55 10 15 16 17 18 19 20 21 22 23 24 IRR Sensitivity ~ 25% 200% 150% % IRR Oil (MBbl) 14 b factor AREA 3 1 30 Day IP (Mcfpd) 100% 50% Gross Capital Costs/ Well ($MM) 0% Total Drill & Case $1.8 Differentials Total Complete $5.0 Oil (% of WTI) 94% Total Capital $6.8 Gas (% of HENRY HUB) 104% NGL (% of WTI) 40% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 60
  • 61. OPERATED EAGLE FORD – AREA 3B DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Gas Type Curve 2 3 4 5 6 7 8 9 10 Gross EURs Oil (MBbl) 33 NGL (MBbl) 387 Production Tax (%) Gas (MMcf) 4,515 1,172 Avg. Working Interest ~ 100% Avg. Royalty Burden Dt (%) 5,169 1.0 55 10 15 ~ 25% Total Drill & Case $1.8 Total Complete $5.0 Total Capital $6.8 10.92 17 18 19 20 21 22 23 24 100% 1 80% % IRR Gross Capital Costs/ Well ($MM) 16 IRR Sensitivity Ownership Total (MBOE) 14 Di (%) Operating Costs Op Costs ($/BOE) 11 12 13 MONTHS b factor AREA 3 1 30 Day IP (Mcfpd) 60% 40% 20% Differentials 0% Oil (% of WTI) Gas (% of HENRY HUB) 104% NGL (% of WTI) 40% $80 94% $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 61
  • 62. OPERATED EAGLE FORD AREA 4 DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 900 800 Gas Type Curve 30 Day IP (Mcfpd) b factor Di (%) Dt (%) 700 AREA 4 1,932 1.5 68 10 600 6,500' Lateral 500 400 5,000' Lateral 300 200 100 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MONTHS * All values based on 6,500’ lateral. Operating Costs Oil (MBbl) 130 Op Costs ($/BOE) NGL (MBbl) 254 Production Tax (%) Gas (MMcf) 1,834 Total (MBOE) 690 IRR Sensitivity 10.47 40% 2 30% Ownership Avg. Working Interest ~ 100% Avg. Royalty Burden % IRR Gross EURs ~ 21% Gross Capital Costs/ Well ($MM) Total Drill & Case $1.6 Differentials Total Complete $5.8 Oil (% of WTI) 94% Total Capital $7.4 Gas (% of HENRY HUB) 107% NGL (% of WTI) 43% 20% 10% 0% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 62
  • 63. Operated Eagle Ford Resource Potential AREA 1 AREA 2 AREA 3A AREA 3B 35,082 21,879 22,226 29,726 EUR/well (MBOE) 475 597 1,266 1,172 Spacing (ac/well) 67 - 93 134 103 103 DCC/well ($MM) 7.3 7.8 6.8 6.8 22 / 41 / 37 12 / 50 / 38 Acreage (ac) Product Mix (O/G/NGL) 9 / 60 / 30 3 / 64 / 33 Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP* 49 / 49 5.9 26 / 26 9.9 95 / 95 51.5 39 / 39 15.8 PUD 8/8 2.7 36 / 36 22.8 79 / 79 70.6 46 / 46 31.0 57 / 57 8.6 62 / 62 32.7 174 / 174 122.1 85 / 85 46.8 Unproved 449 / 427 170.7 101 / 101 41.2 41 / 41 64.7 204 / 204 205.0 Remaining Drilling Locations 457 / 435 173.4 137 / 137 64.0 120 / 120 135.3 250 / 250 236 Total Proved * Includes PDN wells 63
  • 64. Operated Eagle Ford Resource Potential AREA 4 AREA 5 AREA 6 8,268 25,124 1,560 EUR/well (MBOE) 690 931 617 Spacing (ac/well) 93 143 52 DCC/well ($MM) 7.4 7.3 7.9 19 / 44 / 37 0 / 78 / 22 35 / 35 / 30 Acreage (ac) Product Mix (O/G/NGL) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP* 20 / 20 4.1 16 / 16 3.2 13 / 13 5.3 PUD 21 / 21 11.7 0/0 0.0 9/9 4.5 Total Proved 41 / 41 15.8 16 / 16 3.2 22 / 22 9.8 Unproved 48 / 48 33.9 159 / 159 130.7 8/8 4.8 Remaining Drilling Locations 69 / 69 45.6 159 / 159 130.7 17 / 17 9.3 * Includes PDN wells 64
  • 65. EBITDAX Reconciliation EBITDAX (1) (in thousands) Reconciliation of net income (loss) (GAAP) to EBITDAX (non-GAAP) to net cash provided by operating activities (GAAP): Net income (loss) (GAAP) Interest expense Interest income Income tax expense (benefit) Depletion, depreciation, amortization, and asset retirement obligation liability accretion Exploration (2) Impairment of proved properties Abandonment and Impairment of unproved properties Stock-based compensation expense Derivative (gain) loss Cash settlement gain Change in Net Profits Plan liability Gain on divestiture activity EBITDAX (Non-GAAP) Interest expense Interest income Income tax expense (benefit) Exploration Exploratory dry hole expense Amortization of debt discount and deferred financing costs Deferred income taxes Plugging and abandonment Other Changes in current assets and liabilities Net cash provided by operating activities (GAAP) For the Three Months Ended December 31, 2013 2012 $6,996 ($67,138) 24,541 18,368 (3) (19) 8,755 (37,008) 202,640 204,267 20,105 15,778 110,935 170,400 5,046 37,646 6,852 8,454 11,605 (15,590) 9,347 11,461 (15,419) (11,562) (28,484) (4,228) $395,516 $298,229 ($24,541) ($18,368) 3 19 (8,755) 37,008 (20,105) (15,778) (32) 2,310 1,476 1,077 6,936 (36,943) (2,493) (1,052) (154) (379) (10,206) 2,260 $337,645 $268,383 (1) EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion, exploration expense, property impairments, non-cash stock compensation expense, derivative gains and losses net of cash settlements, change in the Net Profit Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors, 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 financial covenants under its credit facility based on its debt to EBITDAX ratio. In addition, 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. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by (used in) operating activities, profitability, or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. (2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration. 65
  • 66. Adjusted Net Income Reconciliation Reconciliation of net income (loss) (GAAP) to adjusted net income (Non-GAAP): For the Three Months Ended December 31, (in thousands, except per share data) Reported Net Income (loss) (GAAP) 2013 $ 2012 6,996 $ (67,138) Adjustments net of tax: (1) Change in Net Profits Plan liability (9,683) (7,249) Derivative (gain) loss 7,288 (9,775) Derivative cash settlement gain 5,870 7,186 (17,888) (2,651) Impairment of properties 69,667 106,841 Abandonment and impairment of unproved properties 23,642 3,164 Gain on divestiture activity Adjusted net income (Non-GAAP): (2) $ 85,892 $ 30,378 Adjusted net income per diluted common share: $ 1.26 $ 0.45 Diluted weighted-average common shares outstanding: 68,354 66,906 (1) For the three-month period ended December 31, 2013, adjustments are shown net of tax and are calculated using a tax rate of 37.2%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. For the twelve-month period ended December 31, 2013, adjustments are shown net of tax using the Company's effective rate of 38.6%, as calculated by dividing income tax expense by income before income taxes shown on the consolidated statement of operations. For the three and twelve-month period ended December 31, 2012, adjustments are shown net of tax and are calculated using an tax rate of 37.3%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. (2) 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 losses net of cash settlements, impairment of proved properties, abandonment and impairment of unproved 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, income 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. 66
  • 67. 1Q14 Guidance 1Q14 FY 2014 12.0 – 12.6 51.0 – 53.5 133 – 140 140 – 147 LOE ($/BOE) $5.25 – $5.50 $5.25 – $5.50 Transportation ($/BOE) $5.75 – $6.05 $5.75 – $6.05 Production taxes (% of pre-derivative oil and gas revenue) 5.0% - 5.5% 5.0% - 5.5% G&A – Cash ($/BOE) $2.00 – $2.20 $2.20 – $2.45 G&A – Cash NPP ($/BOE) $0.20 – $0.35 $0.20 – $0.35 G&A – Non-cash ($/BOE) $0.35 – $0.50 $0.30 – $0.50 G&A Total ($/BOE) $2.55 – $3.05 $2.70 – $3.30 $15.10 – $15.90 $15.10 – $15.90 Production (MMBOE) Average daily production (MBOE/d) DD&A ($/BOE) Effective income tax rate range 37.0% – 37.5% % of income tax that is current <3% 67
  • 68. Oil Derivative Position* Oil Swaps - NYMEX Equivalent Bbls Oil Swaps – WTI swap with LLS basis Differential $/Bbl 2014 Q1 Q2 Q3 Q4 2014 Total 2,175,000 2,373,000 973,000 891,000 6,412,000 $ $ $ $ 2015 Q1 Q2 Q3 Q4 2015 Total 820,000 896,000 615,000 580,000 2,911,000 $ $ $ $ 1,382,000 1,322,000 2,704,000 $ $ 85.19 85.19 Grand Total 425,000 425,000 Grand Total 12,027,000 96.13 94.95 95.25 95.16 2014 Q1 2014 Total $/Bbl 89.09 88.93 89.15 89.14 2016 Q1 Q4 2016 Total Bbls 425,000 $ 100.91 *As of 2/12/14 68
  • 69. Oil Derivative Position* Oil Collars - NYMEX Equivalent Ceiling $/Bbl Bbls Floor $/Bbl 2014 Q1 Q2 Q3 Q4 2014 Total 694,000 431,000 973,000 923,000 3,021,000 $ $ $ $ 115.07 102.50 102.58 102.63 $ $ $ $ 80.97 85.00 85.00 85.00 2015 Q1 Q2 Q3 Q4 2015 Total 882,000 709,000 906,000 869,000 3,366,000 $ $ $ $ 99.53 94.06 91.25 92.19 $ $ $ $ 85.00 85.00 85.00 85.00 Grand Total 6,387,000 *As of 2/12/14 69
  • 70. Gas Derivative Position* Natural Gas Swaps - NYMEX Equivalent MMBTU Natural Gas Collars - NYMEX Equivalent $/MMBTU 2014 Ceiling $/MMBTU MMBTU Floor $/MMBTU 2014 Q1 32,266,000 $ 4.24 Q1 1,540,000 $ 5.59 $ 4.40 Q2 23,758,000 $ 4.06 Q2 4,194,000 $ 5.41 $ 4.51 Q3 24,541,000 $ 4.10 Q3 - Q4 22,014,000 $ 4.13 2014 Total 102,579,000 2015 Q4 - 2014 Total 5,734,000 2015 Q1 17,342,000 $ 4.30 Q1 2,525,000 $ 4.41 $ 4.11 Q2 15,985,000 $ 4.06 Q2 2,297,000 $ 4.44 $ 4.14 Q3 14,950,000 $ 4.18 Q3 2,005,000 $ 4.44 $ 4.14 Q4 9,667,000 $ 4.18 Q4 6,176,000 $ 4.45 $ 4.12 2015 Total 57,944,000 2015 Total 13,003,000 Grand Total 18,737,000 2016 Q1 14,703,000 $ 4.42 Q2 9,130,000 $ 4.19 Q3 7,004,000 $ 4.26 Q4 6,635,000 $ 4.25 2016 Total 37,472,000 2017 Q1 6,299,000 $ Q2 5,974,000 $ 4.31 4.30 Q3 5,712,000 $ 4.30 Q4 5,445,000 $ 4.43 2017 Total 23,430,000 Note: Excludes volumes that were early settled in 1Q14 to unwind trades associated with Anadarko Basin properties sold on 12/30/13. The early settlement of these trades will result in a cash settlement gain of $5.6 million in 1Q14. 2018 Q1 5,203,000 $ 4.43 Q2 4,997,000 $ 4.43 2018 Total 10,200,000 Grand Total 231,625,000 *As of 2/12/14 70
  • 71. NGL Derivative Position* Natural Gas Liquid Swaps - Mont. Belvieu Bbls 2014 Q1 Q2 Q3 Q4 1,429,000 1,096,000 960,000 861,000 2014 Total 4,346,000 Grand Total $/Bbl 4,346,000 $ $ $ $ 57.96 58.04 58.06 58.06 *As of 2/12/14 71