SM Energy - 4th Quarter 2013 Earnings Call

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

3

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%.

4th Quarter 2013 Performance

Production 4Q13 Actual

Performance4Q13 Guidance

Average daily production (MBOE/d) 143.8 139 - 146

Total production (MMBOE) 13.23 12.8 - 13.5

CostsLOE ($/BOE) $4.62 $4.65 - $4.90

Transportation ($/BOE) $5.67 $5.40 - $5.65

Production taxes (% of pre-derivative

oil, gas, & NGL revenue) 4.5% 5.0% - 5.5%

G&A -- Cash ($/BOE) $3.07 $2.15 - $2.35

G&A -- Cash NPP ($/BOE) $0.17 $0.25 - $0.40

G&A -- Non-cash ($/BOE) $0.39 $0.45 - $0.60

TOTAL G&A ($/BOE) ** $3.63 $2.85 - $3.35

DD&A ($/BOE) $15.31 $15.00 - $16.00

Net Income GAAP net income of

$7.0 million, or $0.10

per diluted share.

Adjusted net income*

(non-GAAP) of $85.9

million, or $1.26 per

adjusted diluted

share.

EBITDAX EBITDAX* (non-

GAAP) 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

Proved reserves increased by 46% from 2012.

Liquid volumes of proved reserves increased 49% year over year.

166.5 208.9

126.9

195.5 1.3 5.0 18.2 48.3

219.9

0

100

200

300

400

500

600

Beginning

Proved Reserves

Adds/Infill Acquisitions Revisions Divestitures Production Ending Proved

Reserves

MMBOE

Proved Developed Proved Undeveloped

428.7

53%

Liquids/

47% Gas

54%

Liquids/

46% Gas

293.4

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.

$20.64

$12.84

$17.10

$10.44 $7.77

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

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

2009 2010 2011 2012 2013

Re

se

rv

e R

ep

lac

em

en

t %

F&

D $

/B

OE

Reserve Metrics

Drilling F&D costs, excluding revisions Drilling reserve replacement, excluding revisions

7

405%

Annual Production

8

32.5 32.8 45.8 54.7

68.2 17.3 17.4

22.1 28.3

38.2

9.6

16.7

26.0

0

25

50

75

100

125

150

2009 2010 2011 2012 2013

MB

OE

/d

NGL

Oil

Gas

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.

49.8 50.2

77.5

99.7

132.4

Debt Adjusted Metrics

9

2.1 2.8 3.1

3.8

5.5 0.3 0.3

0.4 0.5

0.6

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.0

1.0

2.0

3.0

4.0

5.0

6.0

2009 2010 2011 2012 2013

BO

E/

D.A

. S

ha

re

BO

E/

D.A

. S

ha

re

Proved reserves per debt

adjusted share

Production per debt

adjusted share

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.

Operational Update:

Development Programs

10

Quarterly Production

11

57.9 59.7 71.7 69.7 71.5

31.3 34.8 35.5 41.6 40.8

20.8 20.5

24.6 27.5 31.5

0

20

40

60

80

100

120

140

160

4Q12 1Q13 2Q13 3Q13 4Q13

MB

OE

/d

NGL

Oil

Gas

4Q13 production mix comprised of 50% liquids.

Quarterly production increased 31% from 4Q12 to 4Q13.

Liquids volumes grew 39% from 4Q12 to 4Q13.

110.0 115.0

131.8 138.8 143.8

Operated Eagle Ford Net Production

10% sequential production

growth quarter over quarter;

65% quarterly production

growth from 4Q12 to 4Q13.

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.

12

26.1 30.4 41.7 38.8 42.8

3.9 6.3

5.5 8.2 7.8

15.2 15.1

18.9 21.1 24.2

0

10

20

30

40

50

60

70

80

4Q12 1Q13 2Q13 3Q13 4Q13

MB

OE

/d

NGL Oil Gas

74.8

~145,000 total net acres ~ 65,000 net acres - Briscoe Ranch

~ 15,000 net acres - Apache Ranch

~ 65,000 net acres - Galvan Ranch

Operational Highlights

45.2 51.8

68.1 66.1

Operated Eagle Ford Type Curve Regions

Area 5

Area 6

Area 1

Area 4

Area 2

Area 5

Area 3A

Area 3B

13

Operated Eagle Ford 2013 Activity

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 58.6

Area 6

Area 1

Area 4

Area 2

Area 5

Area 3A

Area 3B

14

2013 Wells

Prior Year Wells

Op. Eagle Ford CWC Efficiencies

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

2012 Avg Area 1,2,4

Well

2013 Avg Area 1,2,4

Well

2012 Avg Area 3 Well 2013 Avg Area 3 Well

CW

C C

ap

ita

l ($

MM

) 14% Reduction 14% Reduction

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

Type Curve

Area

Well

Count

1 12

2 21

3 60

4 8

5 0

6 0

Total 101

Area 6

Area 1

Area 4

Area 2

Area 5

Area 3A

Area 3B

17

2014 Planned Activity

5 Year Development Plan

2014 2015 2016 2017 2018

18

Area 6

Area 1

Area 4

Area 2

Area 5

Area 3A

Area 3B

Non-operated Eagle Ford

1% sequential production

growth quarter over

quarter.

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.

Operational Highlights Net Production

19

15.5 16.0 17.4 19.8 20.0

0

5

10

15

20

25

4Q12 1Q13 2Q13 3Q13 4Q13

MB

OE

/d

Bakken/Three Forks

8% sequential growth quarter over

quarter; 35% quarterly production

growth 4Q12 to 4Q13.

The Company operated 3 rigs during

4Q13 and made 6 gross flowing

completions.

Net Production Operational Highlights

Total Bakken/TFS net

acreage

~159,000

Focus area total net acreage

~79,000

RAVEN/BEAR DEN

~43,000acres

GOOSENECK

~36,000 acres

20

11.9 12.2 13.7 14.9 16.1

0

2

4

6

8

10

12

14

16

18

4Q12 1Q13 2Q13 3Q13 4Q13

MB

OE

/d

Raven/Bear Den

= 2013 BAKKEN WELL

= 2013 THREE FORKS WELL

Raven/Bear Den Bakken / TFS Operated 2013 Activity

Type Curve Area

Well Count

Gross/Net

Net Reserve Add

(MMBOE)

Raven/Bear Den Bakken 17/ 10 3.9

Raven/Bear Den TFS 13 / 8 2.6

Total 30 / 18 6.5

21

North Dakota

Gooseneck

Gooseneck TFS Operated 2013 Activity

Type Curve Area

Well Count

Gross/Net

Net Reserve Add

(MMBOE)

Gooseneck TFS 15 / 11 3.5

22

North Dakota

Operated Bakken/Three Forks CWC Efficiencies

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

2012 Avg Raven/Bear

Den Well

2013 Avg Raven/Bear

Den Well

2012 Avg Gooseneck

Well

2013 Avg Gooseneck

Well

CW

C C

ap

ita

l ($

MM

)

4% Reduction

4% Reduction

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.


Modify drilling target interval to improve well performance.


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.*

Middle Bakken

Upper Bakken Shale

Lower Bakken Shale

Three Forks 1st Bench

Three Forks 2nd Bench

1060’

1060’

25

*Amounts not included in inventory table in the Appendix.

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.

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.*

26

Gooseneck 2014 Bakken Wells


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.

27

2014 planned wells


= 2014 BAKKEN WELL


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

28

2014 planned activity

Gooseneck

Gooseneck TFS 2014 Activity

Type Curve Area

Well

Count

Goosneck TFS 13 / 8

29


2014 planned activity

Operational Update:

New Ventures

30

Powder River Basin

31

WY

Dandy (Frontier)

30 day IP: 927 BOE/d

Loco (Frontier)

30 Day IP: 1,408 BOE/d

Bridger (Shannon)

30 day IP: 499 BOE/d

Op PDP Hz

Op 2014 Hz

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.

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.

Permian Region Net Production Operational Highlights

32

5.5 5.3 6.6 6.8 7.3

0

1

2

3

4

5

6

7

8

4Q12 1Q13 2Q13 3Q13 4Q13

MB

OE

/d

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.

Midland Basin Focus Map

Midland Basin

Buffalo ~47,500 Net acres

Sweetie Peck ~13,500 Net acres

33

Sweetie Peck – Horiz Well Performance

Well Name

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

34

Wolfcamp ‘D’ / Cline: ~50

wells (Test in 4Q14)

Lower Spraberry: ~105

wells

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

35

* 96 wells assumes 50’ clearance from vertical

wells and 880’ spacing.

Producing

2014 planned wells

Add’l Locations

Geology Sweetie Peck to Buffalo

36

Buffalo

Sweetie

Peck

Buffalo Program

Continue production test on

Tatonka 1H.

Drill and complete a

Wolfcamp ‘D’ test in 2Q14.

Well Name

Target

Interval

Lateral

Length Stages

Peak 30-Day IP

(BOE/d) % Oil Proppant

Lift

Mechanism

Tatonka 1H Wolfcamp B 5,560 28 376 89 LWC ESP

2014 Program

37

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

W&T Offshore

Chablis #5H

24-hr IP rate: 530 BOE/d

WC A

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

3000 4000 5000 6000 7000 8000 9000 10000 11000 12000

30

Da

y I

P (

BO

E)

Lateral Length (ft)

Midland Basin Wolfcamp B Wells

SM Energy wells, in blue, represent a Peak 30 day average.

Graph contains allocated month production figures from IHS for non SM wells.

Dorcus 3035H

CVX 4134H

Britain 3133H

Tatonka #1H

38

SM Energy East Texas Prospect Areas

39

Independence ~26,000 Net acres

Deep Pines West ~90,000 Net acres

Deep Pines Central ~91,000 Net acres

Deep Pines East ~8,500 Net acres

Three Geologic Concepts

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, over-

pressured marine sandstones.

Total Net Acreage: ~215,000

Woodbine Trap Model

Porous,

Permeable, Wet

Sandstones

Eagle Ford Shale

(Hydrocarbon Source)

Austin Chalk

Buda Limestone

Tight, Hydrocarbon-

Saturated Shaley

Sandstones

(Reservoir & Seal)

Hydrocarbon-Saturated

Shaley Sandstones

(Woodbine Rim Play)

Conventional Woodbine

Hydrocarbon Traps

Woodbine

Sandstones

Conventional Trap

Normally Pressured Over-Pressured

40

Unconventional Trap

SM Target

SM Energy East Texas Prospect Areas

41

Brollier 1H

Well Name

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

Horizon 2H

2014 East Texas Program

* Non-operated

42

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 Est. Frac Date

12H Eagle Ford 3Q14


Matt Dillon Woodbine 1Q14

Little Joe Woodbine 2Q14

Doc Woodbine 2Q14

Ben Woodbine 3Q14


Cameron

Heirs

Austin

Chalk

3Q14


Blackstone

Page *

Austin

Chalk

2Q14

Walter

Johnson

Woodbine 2Q14

Financial Update

43

Financial Position

$350

$350

$400

$500

$1,607

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

December 31, 2013

TOTAL BOOK

CAPITALIZATION

(in millions)

Revolving Credit Facility

Senior Notes due 2023




44

Stockholders’ Equity

$0

At December 31, 2013,

the Company’s net debt

to trailing EBITDAX was

0.9 and net debt to book

capitalization was 45%.

Current revolver

commitment is $1.3

billion with borrowing

base of $2.2 billion.

Financial Position

Revolving Credit Facility





45

$0

$500

$1,000

$1,500

$2,000

$2,500

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Debt Maturities

(in millions)

Debt to TTM EBITDAX

1.1 1.2

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

4.5x

5.0x

Average: 2.4x

SM @

12/31/13

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.

SM @

9/30/13

SM Energy’s debt to trailing twelve-month EBITDAX is below

its peer average of 2.4x.

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.

47

$7.81 $10.21

$13.66 $12.72

$18.35

$0.00

$5.00

$10.00

$15.00

$20.00

2009 2010 2011 2012 2013

$/

D.A

. S

ah

re

EBITDAX Per Debt Adjusted Share

Key Takeaways

48

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.

Appendix

49

Other $60 East Texas

$55

PRB $140

Permian

Shales

$155

Bakken /

Three

Forks $350 Non-

Operated

Eagle

Ford $250

Operated

Eagle

Ford $650

$65 $200

Development

New Ventures

Non Drilling

$1,660

2014 Capital Budget ($ in millions)

2014 capital budget

of ~$1.9 billion

50

Focused EFS and

Bakken programs

account for 75% of

development budget.

Over 75% of

development capital

is allocated to

projects operated by

SM Energy.

Condensate Update

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

South Texas & Gulf Coast

% Oil Realization to LLS

81% 85% 88% 86% 86%

$21.33 $19.64

$10.63

$4.18 $3.58

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

4Q12 1Q13 2Q13 3Q13 4Q13

LL

S P

rem

ium

to

WT

I (B

lue

lin

e)

SM

Oil

Re

ali

za

tio

n %

of

LL

S

4Q13 Regional Realizations Benchmark

NYMEX WTI OIL (Bbl) $ 97.41

Hart Composite NGL (Bbl) $ 43.13

NYMEX Henry Hub Gas (MMBTU) $ 3.82

Production Volumes STGC Rockies Mid-Con Permian SM Total

Oil (MBbls) 1,449 1,699 113 493 3,756

Gas (MMcf) 27,442 1,708 9,285 1,064 39,499

NGL (MBbls) 2,813 5 75 0 2,894

MBOE 8,836 1,989 1,735 671 13,233

Revenue (in thousands)

Oil $ 125,710 $ 142,958 $ 9,895 $ 46,070 $ 324,810

Gas 101,878 10,523 37,268 7,391 157,060

NGL 108,718 282 2,789 8 111,798

Total $ 336,306 $ 153,763 $ 49,953 $ 53,468 $ 593,667

Expenses

LOE $ 19,319 $ 20,417 $ 8,354 $ 12,886 $ 61,152

Transportation $ 71,299 $ 1,558 $ 2,163 $ 32 $ 75,052

Production Taxes $ 6,518 $ 15,518 $ 1,401 $ 3,108 $ 26,550

Per Unit Metrics:

Realized Oil/Bbl $ 86.74 $ 84.15 $ 87.77 $ 93.42 $ 86.48

% of Benchmark – WTI 89 % 86 % 90 % 96 % 89 %

Realized Gas/Mcf $ 3.71 $ 6.16 $ 4.01 $ 6.95 $ 3.98

% of Benchmark - NYMEX HH 97 % 161 % 105 % 182 % 104 %

Realized NGL/Bbl $ 38.64 $ 56.42 $ 37.08 $ 32.09 $ 38.63

% of Benchmark – HART 90 % 131 % 86 % 74 % 90 %

Realized BOE $ 38.06 $ 77.32 $ 28.78 $ 79.73 $ 44.86

LOE/BOE $ 2.19 $ 10.27 $ 4.81 $ 19.21 $ 4.62

Transportation/BOE $ 8.07 $ 0.78 $ 1.25 $ 0.05 $ 5.67

Production Tax - % of Total Revenue 1.9 % 10.1 % 2.8 % 5.8 % 4.5 %

* Totals may not sum due to rounding.

52

0

200

400

600

800

1,000

1,200

1,400

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

BKN TYPE CURVE

TFS TYPE CURVE

BAKKEN/THREE FORKS OPERATED RAVEN/BEAR DEN

IRR Sensitivity

Type Curve (1st 24 Months)

Gross Capital Costs/ Well ($MM)

Total Drill & Case $3.5

Total Complete $5.5

Total Capital $9.0

Ownership

Avg. Working Interest ~ 55%

Avg. Royalty Burden ~ 17%

Differentials

Oil (% of WTI) 92%

Gas (% of HENRY HUB) 156%

NGL (% of WTI) -

Gross EURs

Bakken Three Forks

Oil (MBbl) 438 375

NGL (MBbl) - -

Gas (MMcf)* 543 416

Total (MBOE) 529 444

Operating Costs

Op Costs ($/BOE) 4.90 -

5.60

Production Tax (%) 11

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

oil price.

• Economics include shrink for field usage *Gas EUR values are net of fuel usage (10%)

Oil Type

Curve

30 Day IP

(Bopd)

b factor Di

(%)

Dt (%)

Bakken 671 1.4 80 8

Three Forks 542 1.5 80 8

0%

20%

40%

60%

80%

100%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil

BAKKEN THREE FORKS

53

0

100

200

300

400

500

600

700

800

900

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

THREE FORKS OPERATED GOOSENECK

IRR Sensitivity




Total Complete $3.7

Total Capital $6.5

Ownership



Differentials

Oil (% of WTI) 89%


NGL (% of WTI) -

Gross EURs

Oil (MBbl) 368

NGL (MBbl) -

Gas (MMcf)* 172

Total (MBOE) 397

Operating Costs

Op Costs ($/BOE) 2.06


• 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

Oil Type

Curve

30 Day Max

IP (Bopd)

b

factor

Di

(%)

Dt

(%)

Three Forks 324 1.4 63 8

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

0%

20%

40%

60%

80%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil

THREE FORKS

54

Operated Bakken/Three Forks Resource Potential

Gooseneck

Three Forks

Raven/Bear Den

Bakken

Raven/Bear Den

Three Forks

Acreage (ac) 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

Product Mix (O/G/NGL) 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0

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

55

* 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

Non-Operated Bakken/Three Forks Resource Potential

Gooseneck

Three Forks

Raven/Bear Den

Bakken

Raven/Bear Den

Three Forks

Acreage (ac) 36,207 43,185* 43,185*

EUR/well (MBOE) ** 367 529 444


DCC/well ($MM) 6.5 9.0 9.0

Product Mix (O/G/NGL) 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0

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

56

* 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

Operated Eagle Ford Type Curve Regions

Area 5

Area 6

Area 1

Area 4

Area 2

Area 5

Area 3A

Area 3B

57

0

100

200

300

400

500

600

700

800

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

6,500' Lateral

5,000' Lateral

OPERATED EAGLE FORD AREA 1

IRR Sensitivity


Gas Type

Curve

30 Day IP

(Mcfpd)

b factor Di

(%)

Dt

(%)

AREA 1 1,423 1.5 69 10



Total Complete $5.7

Total Capital $7.3

Ownership



Differentials

Oil (% of WTI) 94%


NGL (% of WTI) 43%

Gross EURs

Oil (MBbl) 106

NGL (MBbl) 174

Gas (MMcf) 1,164

Total (MBOE) 475

Operating Costs



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

oil price.

0%

5%

10%

15%

20%

25%

30%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil

58

* All values based on 6,500’ lateral.

0

200

400

600

800

1,000

1,200

1,400

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

6,500' Lateral

5,000' Lateral


IRR Sensitivity




Total Complete $6.2

Total Capital $7.8

Ownership



Differentials

Oil (% of WTI) 94%


NGL (% of WTI) 44%

Gross EURs

Oil (MBbl) 73

NGL (MBbl) 228

Gas (MMcf) 1,778

Total (MBOE) 597

Operating Costs



0%

10%

20%

30%

40%

50%

60%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil

• Assumes natural gas price of $4.50/MMbtu & NGL price equal

to 45% of crude oil price.

Gas Type

Curve

30 Day IP

(Mcfpd)

b

factor

Di

(%)

Dt

(%)

AREA 2 3,829 1.2 75 10

59


0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

OPERATED EAGLE FORD – AREA 3A

IRR Sensitivity


Gas Type

Curve

30 Day IP

(Mcfpd)

b

factor

Di

(%)

Dt

(%)

AREA 3 5,169 1.0 55 10



Total Complete $5.0

Total Capital $6.8

Ownership



Differentials

Oil (% of WTI) 94%


NGL (% of WTI) 40%

Gross EURs

Oil (MBbl) 115

NGL (MBbl) 391

Gas (MMcf) 4,564

Total (MBOE) 1,266

Operating Costs





60

0%

50%

100%

150%

200%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

OPERATED EAGLE FORD – AREA 3B

IRR Sensitivity


Gas Type

Curve

30 Day IP

(Mcfpd)

b

factor

Di

(%)

Dt

(%)

AREA 3 5,169 1.0 55 10



Total Complete $5.0

Total Capital $6.8

Ownership



Differentials

Oil (% of WTI) 94%


NGL (% of WTI) 40%

Gross EURs

Oil (MBbl) 33

NGL (MBbl) 387

Gas (MMcf) 4,515

Total (MBOE) 1,172

Operating Costs





0%

20%

40%

60%

80%

100%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil

61

0

100

200

300

400

500

600

700

800

900

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

DA

ILY

EQ

UIV

AL

EN

T

PR

OD

UC

TIO

N (

BO

EP

D)

MONTHS

6,500' Lateral

5,000' Lateral


IRR Sensitivity


Gas Type

Curve

30 Day IP

(Mcfpd)

b

factor

Di

(%)

Dt

(%)

AREA 4 1,932 1.5 68 10



Total Complete $5.8

Total Capital $7.4

Ownership



Differentials

Oil (% of WTI) 94%


NGL (% of WTI) 43%

Gross EURs

Oil (MBbl) 130

NGL (MBbl) 254

Gas (MMcf) 1,834

Total (MBOE) 690

Operating Costs



0%

10%

20%

30%

40%

$80 $85 $90 $95 $100 $105

% I

RR

$/BBL - NYMEX Oil



62


Operated Eagle Ford Resource Potential AREA 1 AREA 2 AREA 3A AREA 3B

Acreage (ac) 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

Product Mix

(O/G/NGL)

22 / 41 / 37 12 / 50 / 38 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

Total Proved 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

63

* Includes PDN wells

Operated Eagle Ford Resource Potential AREA 4 AREA 5 AREA 6

Acreage (ac) 8,268 25,124 1,560

EUR/well (MBOE) 690 931 617


DCC/well ($MM) 7.4 7.3 7.9

Product Mix

(O/G/NGL)

19 / 44 / 37 0 / 78 / 22 35 / 35 / 30

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

64

* Includes PDN wells

EBITDAX Reconciliation EBITDAX (1)

(in thousands)

Reconciliation of net income (loss) (GAAP) to EBITDAX (non-GAAP) to net cash For the Three Months Ended

provided by operating activities (GAAP): December 31,

2013 2012

Net income (loss) (GAAP) $6,996 ($67,138)

Interest expense 24,541 18,368

Interest income (3) (19)

Income tax expense (benefit) 8,755 (37,008)

Depletion, depreciation, amortization, and asset retirement obligation liability accretion 202,640 204,267

Exploration (2) 20,105 15,778

Impairment of proved properties 110,935 170,400

Abandonment and Impairment of unproved properties 37,646 5,046

Stock-based compensation expense 6,852 8,454

Derivative (gain) loss 11,605 (15,590)

Cash settlement gain 9,347 11,461

Change in Net Profits Plan liability (15,419) (11,562)

Gain on divestiture activity (28,484) (4,228)

EBITDAX (Non-GAAP) $395,516 $298,229

Interest expense ($24,541) ($18,368)

Interest income 3 19

Income tax expense (benefit) (8,755) 37,008

Exploration (20,105) (15,778)

Exploratory dry hole expense (32) 2,310

Amortization of debt discount and deferred financing costs 1,476 1,077

Deferred income taxes 6,936 (36,943)

Plugging and abandonment (2,493) (1,052)

Other (154) (379)

Changes in current assets and liabilities (10,206) 2,260

Net cash provided by operating activities (GAAP) $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) 2013 2012

Reported Net Income (loss) (GAAP) $ 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

Gain on divestiture activity (17,888) (2,651)

Impairment of properties 69,667 106,841

Abandonment and impairment of unproved properties 23,642 3,164

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

Production (MMBOE) 12.0 – 12.6 51.0 – 53.5

Average daily production (MBOE/d) 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

DD&A ($/BOE) $15.10 – $15.90 $15.10 – $15.90

Effective income tax rate range 37.0% – 37.5%

% of income tax that is current <3%

67

Oil Derivative Position* Oil Swaps - NYMEX Equivalent Oil Swaps – WTI swap with LLS basis Differential

Bbls $/Bbl Bbls $/Bbl

2014 2014

Q1 2,175,000 $ 96.13 Q1 425,000 $ 100.91

Q2 2,373,000 $ 94.95 2014 Total 425,000

Q3 973,000 $ 95.25

Q4 891,000 $ 95.16

2014 Total 6,412,000 Grand Total 425,000

2015

Q1 820,000 $ 89.09

Q2 896,000 $ 88.93

Q3 615,000 $ 89.15

Q4 580,000 $ 89.14

2015 Total 2,911,000

2016

Q1 1,382,000 $ 85.19

Q4 1,322,000 $ 85.19

2016 Total 2,704,000

Grand Total 12,027,000

*As of 2/12/14

68

Oil Derivative Position* Oil Collars - NYMEX Equivalent

Ceiling Floor

Bbls $/Bbl $/Bbl

2014

Q1 694,000 $ 115.07 $ 80.97

Q2 431,000 $ 102.50 $ 85.00

Q3 973,000 $ 102.58 $ 85.00

Q4 923,000 $ 102.63 $ 85.00

2014 Total 3,021,000

2015

Q1 882,000 $ 99.53 $ 85.00

Q2 709,000 $ 94.06 $ 85.00

Q3 906,000 $ 91.25 $ 85.00

Q4 869,000 $ 92.19 $ 85.00

2015 Total 3,366,000


*As of 2/12/14

69

Gas Derivative Position* Natural Gas Swaps - NYMEX Equivalent Natural Gas Collars - NYMEX Equivalent

Ceiling Floor

MMBTU $/MMBTU MMBTU $/MMBTU $/MMBTU

2014 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 Q4 -

2014 Total 102,579,000 2014 Total 5,734,000

2015 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

2016

Q1 14,703,000 $ 4.42 Grand Total 18,737,000

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 $ 4.31

Q2 5,974,000 $ 4.30

Q3 5,712,000 $ 4.30

Q4 5,445,000 $ 4.43

2017 Total 23,430,000

2018

Q1 5,203,000 $ 4.43

Q2 4,997,000 $ 4.43

2018 Total 10,200,000


*As of 2/12/14

70

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.

NGL Derivative Position*

Natural Gas Liquid Swaps - Mont. Belvieu

Bbls $/Bbl

2014

Q1 1,429,000 $ 57.96

Q2 1,096,000 $ 58.04

Q3 960,000 $ 58.06

Q4 861,000 $ 58.06

2014 Total

4,346,000


*As of 2/12/14

71

SM Energy - 4th Quarter 2013 Earnings Call

Investor Relations

Transcript of SM Energy - 4th Quarter 2013 Earnings Call