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 $395.5
million.
* Please see adjusted net income and EBITDAX reconciliations in the Appendix.
** 4Q13 G&A per unit expenses were higher than guidance due to performance-based bonus compensation.
4
9. Debt Adjusted Metrics
BOE/D.A. Share
5.0
4.0
3.0
Proved reserves per debt
adjusted share
Production per debt
adjusted share
0.3
2.1
0.6
0.4
0.5
2.8
0.5
0.4
0.3
2.0
1.0
0.6
0.7
5.5
3.1
3.8
0.3
0.2
BOE/D.A. Share
6.0
0.1
0.0
0.0
2009
2010
2011
2012
2013
Proved reserves per debt adjusted share grew 47% year over year and 25%
compound annual growth over a 3-year period ending December 31, 2013.
Production per debt adjusted share grew by 33% year over year, and 26%
compound annual growth over a 3-year period ending December 31, 2013.
9
12. Operated Eagle Ford
Net Production
Operational Highlights
The Company made 20
flowing completions during
4Q13 and made 95 flowing
completions in 2013.
At year-end 2013, SM Energy
had ~240 PDP locations, and
~200 PUD locations with an
associated ~240 MMBOE of
total proved reserves
booked.
80
74.8
66.1
68.1
51.8
18.9
21.1
15.1
5.5
8.2
41.7
38.8
42.8
2Q13
3Q13
4Q13
70
MBOE/d
10% sequential production
growth quarter over quarter;
65% quarterly production
growth from 4Q12 to 4Q13.
60
50
45.2
40
15.2
3.9
30
20
10
24.2
7.8
6.3
26.1
30.4
4Q12
1Q13
0
NGL
Oil
Gas
~145,000 total net acres
~ 65,000 net acres - Briscoe Ranch
~ 15,000 net acres - Apache Ranch
~ 65,000 net acres - Galvan Ranch
12
13. Operated Eagle Ford Type Curve Regions
Area 6
Area 1
Area 4
Area 3A
Area 2
Area 5
Area 3B
Area 5
13
14. Operated Eagle Ford 2013 Activity
Area 6
Area 1
Area 4
Area 3A
Area 2
Type Curve
Area
2013 Well
Count
Net Reserve
Add (MMBOE)
1
15
2.1
2
4
2.3
3
61
47.7
4
4
1.4
5
1
0.5
6
10
4.7
Total
95
Area 3B
58.6
Area 5
2013 Wells
Prior Year Wells
14
15. Op. Eagle Ford CWC Efficiencies
8.0
CWC Capital ($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
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
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
$0
4Q12
1Q13
2Q13
3Q13
4Q13
LLS Premium to WTI (Blue line)
SM Oil Realization % of LLS
100%
Substantially all of SM
Energy’s Eagle Ford
condensate trades off of an
LLS benchmark.
The Company’s condensate
realization has remained
stable as a percentage of the
LLS benchmark.
SM Energy has approximately
10,0000 Bbls/d of firm
condensate sales contracts
utilizing a mixture of fixed
and floating gravity
differentials.
51
53. BAKKEN/THREE FORKS OPERATED RAVEN/BEAR DEN
DAILY EQUIVALENT
PRODUCTION (BOEPD)
Type Curve (1st 24 Months)
Oil Type
Curve
1,000
b factor
Di
(%)
Dt (%)
671
1.4
80
8
Three Forks
1,200
30 Day IP
(Bopd)
Bakken
1,400
542
1.5
80
8
800
BKN TYPE CURVE
600
TFS TYPE CURVE
400
200
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MONTHS
Gross EURs
IRR Sensitivity
Operating Costs
Bakken
4.90 5.60
100%
11
80%
438
375
NGL (MBbl)
-
-
Gas (MMcf)*
543
416
Ownership
Total (MBOE)
529
444
Avg. Working Interest
~ 55%
Avg. Royalty Burden
~ 17%
Gross Capital Costs/ Well ($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
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