SM Energy - 4th Quarter 2013 Earnings Call
-
Upload
company-spotlight -
Category
Investor Relations
-
view
3.982 -
download
1
Transcript of 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.
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.*
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
*Amounts not included in inventory table in the Appendix.
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
*Amounts not included in inventory table in the Appendix.
= 2014 BAKKEN WELL
= 2014 THREE FORKS 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 THREE FORKS WELL
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
Well Target Est. Frac Date
Matt Dillon Woodbine 1Q14
Little Joe Woodbine 2Q14
Doc Woodbine 2Q14
Ben Woodbine 3Q14
Well Target Est. Frac Date
Cameron
Heirs
Austin
Chalk
3Q14
Well Target Est. Frac Date
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
Senior Notes due 2019
Senior Notes due 2024
Senior Notes due 2021
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
Senior Notes due 2023
Senior Notes due 2019
Senior Notes due 2024
Senior Notes due 2021
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
$/BBL - NYMEX Oil
BAKKEN THREE FORKS
53
0
100
200
300
400
500
600
700
800
900
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
DA
ILY
EQ
UIV
AL
EN
T
PR
OD
UC
TIO
N (
BO
EP
D)
MONTHS
THREE FORKS OPERATED GOOSENECK
IRR Sensitivity
Type Curve (1st 24 Months)
Gross Capital Costs/ Well ($MM)
Total Drill & Case $2.8
Total Complete $3.7
Total Capital $6.5
Ownership
Avg. Working Interest ~ 67%
Avg. Royalty Burden ~ 19%
Differentials
Oil (% of WTI) 89%
Gas (% of HENRY HUB) 116%
NGL (% of WTI) -
Gross EURs
Oil (MBbl) 368
NGL (MBbl) -
Gas (MMcf)* 172
Total (MBOE) 397
Operating Costs
Op Costs ($/BOE) 2.06
Production Tax (%) 11
• 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
Spacing (ac/well) 320 320 320
DCC/well ($MM) 6.5 9.0 9.0
Product Mix (O/G/NGL) 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0
Gross/Net
Count
Net Resource
(MMBOE)
Gross/Net
Count
Net Resource
(MMBOE)
Gross/Net
Count
Net Resource
(MMBOE)
PDP 4 / 0.5 0.1 76 / 14 3.5 36 / 5 1.4
PUD 0 / 0 0.0 56 / 12 5.0 16 / 2 0.9
Total Proved 4 / 0.5 0.1 132 / 26 8.5 52 / 7 2.3
Unproved 31 / 5 1.1 223 / 20 7.8 297 / 38 12.7
Remaining Drilling Locations 31 / 5 1.1 279 / 32 12.8 313 / 40 13.6
56
* Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent.
** Gas EUR values are net of fuel usage
Operated Eagle Ford Type Curve Regions
Area 5
Area 6
Area 1
Area 4
Area 2
Area 5
Area 3A
Area 3B
57
0
100
200
300
400
500
600
700
800
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
DA
ILY
EQ
UIV
AL
EN
T
PR
OD
UC
TIO
N (
BO
EP
D)
MONTHS
6,500' Lateral
5,000' Lateral
OPERATED EAGLE FORD AREA 1
IRR Sensitivity
Type Curve (1st 24 Months)
Gas Type
Curve
30 Day IP
(Mcfpd)
b factor Di
(%)
Dt
(%)
AREA 1 1,423 1.5 69 10
Gross Capital Costs/ Well ($MM)
Total Drill & Case $1.6
Total Complete $5.7
Total Capital $7.3
Ownership
Avg. Working Interest ~ 97%
Avg. Royalty Burden ~ 22%
Differentials
Oil (% of WTI) 94%
Gas (% of HENRY HUB) 108%
NGL (% of WTI) 43%
Gross EURs
Oil (MBbl) 106
NGL (MBbl) 174
Gas (MMcf) 1,164
Total (MBOE) 475
Operating Costs
Op Costs ($/BOE) 10.60
Production Tax (%) 3
• 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
$/BBL - NYMEX Oil
58
* All values based on 6,500’ lateral.
0
200
400
600
800
1,000
1,200
1,400
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
DA
ILY
EQ
UIV
AL
EN
T
PR
OD
UC
TIO
N (
BO
EP
D)
MONTHS
6,500' Lateral
5,000' Lateral
OPERATED EAGLE FORD AREA 2
IRR Sensitivity
Type Curve (1st 24 Months)
Gross Capital Costs/ Well ($MM)
Total Drill & Case $1.6
Total Complete $6.2
Total Capital $7.8
Ownership
Avg. Working Interest ~ 100%
Avg. Royalty Burden ~ 25%
Differentials
Oil (% of WTI) 94%
Gas (% of HENRY HUB) 107%
NGL (% of WTI) 44%
Gross EURs
Oil (MBbl) 73
NGL (MBbl) 228
Gas (MMcf) 1,778
Total (MBOE) 597
Operating Costs
Op Costs ($/BOE) 10.76
Production Tax (%) 2
0%
10%
20%
30%
40%
50%
60%
$80 $85 $90 $95 $100 $105
% I
RR
$/BBL - NYMEX Oil
• Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.
Gas Type
Curve
30 Day IP
(Mcfpd)
b
factor
Di
(%)
Dt
(%)
AREA 2 3,829 1.2 75 10
59
* All values based on 6,500’ lateral.
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
DA
ILY
EQ
UIV
AL
EN
T
PR
OD
UC
TIO
N (
BO
EP
D)
MONTHS
OPERATED EAGLE FORD – AREA 3A
IRR Sensitivity
Type Curve (1st 24 Months)
Gas Type
Curve
30 Day IP
(Mcfpd)
b
factor
Di
(%)
Dt
(%)
AREA 3 5,169 1.0 55 10
Gross Capital Costs/ Well ($MM)
Total Drill & Case $1.8
Total Complete $5.0
Total Capital $6.8
Ownership
Avg. Working Interest ~ 100%
Avg. Royalty Burden ~ 25%
Differentials
Oil (% of WTI) 94%
Gas (% of HENRY HUB) 104%
NGL (% of WTI) 40%
Gross EURs
Oil (MBbl) 115
NGL (MBbl) 391
Gas (MMcf) 4,564
Total (MBOE) 1,266
Operating Costs
Op Costs ($/BOE) 10.38
Production Tax (%) 2
• Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.
60
0%
50%
100%
150%
200%
$80 $85 $90 $95 $100 $105
% I
RR
$/BBL - NYMEX Oil
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
DA
ILY
EQ
UIV
AL
EN
T
PR
OD
UC
TIO
N (
BO
EP
D)
MONTHS
OPERATED EAGLE FORD – AREA 3B
IRR Sensitivity
Type Curve (1st 24 Months)
Gas Type
Curve
30 Day IP
(Mcfpd)
b
factor
Di
(%)
Dt
(%)
AREA 3 5,169 1.0 55 10
Gross Capital Costs/ Well ($MM)
Total Drill & Case $1.8
Total Complete $5.0
Total Capital $6.8
Ownership
Avg. Working Interest ~ 100%
Avg. Royalty Burden ~ 25%
Differentials
Oil (% of WTI) 94%
Gas (% of HENRY HUB) 104%
NGL (% of WTI) 40%
Gross EURs
Oil (MBbl) 33
NGL (MBbl) 387
Gas (MMcf) 4,515
Total (MBOE) 1,172
Operating Costs
Op Costs ($/BOE) 10.92
Production Tax (%) 1
• Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.
0%
20%
40%
60%
80%
100%
$80 $85 $90 $95 $100 $105
% I
RR
$/BBL - NYMEX Oil
61
0
100
200
300
400
500
600
700
800
900
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
DA
ILY
EQ
UIV
AL
EN
T
PR
OD
UC
TIO
N (
BO
EP
D)
MONTHS
6,500' Lateral
5,000' Lateral
OPERATED EAGLE FORD AREA 4
IRR Sensitivity
Type Curve (1st 24 Months)
Gas Type
Curve
30 Day IP
(Mcfpd)
b
factor
Di
(%)
Dt
(%)
AREA 4 1,932 1.5 68 10
Gross Capital Costs/ Well ($MM)
Total Drill & Case $1.6
Total Complete $5.8
Total Capital $7.4
Ownership
Avg. Working Interest ~ 100%
Avg. Royalty Burden ~ 21%
Differentials
Oil (% of WTI) 94%
Gas (% of HENRY HUB) 107%
NGL (% of WTI) 43%
Gross EURs
Oil (MBbl) 130
NGL (MBbl) 254
Gas (MMcf) 1,834
Total (MBOE) 690
Operating Costs
Op Costs ($/BOE) 10.47
Production Tax (%) 2
0%
10%
20%
30%
40%
$80 $85 $90 $95 $100 $105
% I
RR
$/BBL - NYMEX Oil
• Assumes natural gas price of $4.50/MMbtu & NGL price equal
to 45% of crude oil price.
62
* All values based on 6,500’ lateral.
Operated Eagle Ford Resource Potential AREA 1 AREA 2 AREA 3A AREA 3B
Acreage (ac) 35,082 21,879 22,226 29,726
EUR/well (MBOE) 475 597 1,266 1,172
Spacing (ac/well) 67 - 93 134 103 103
DCC/well ($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
Spacing (ac/well) 93 143 52
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
Grand Total 6,387,000
*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
Grand Total 231,625,000
*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
Grand Total 4,346,000
*As of 2/12/14
71