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2018 RESULTS &
2019 OPERATING PLAN
FEBRUARY 20, 2019
2
PLEASE READ
THIS PRESENTATION MAKES REFERENCE TO:
Forward-looking statements
This presentation contains forward-looking statements within the meaning of securities laws. The words "anticipate," "budget,"
"estimate," "expect," "forecast," "guidance," "plan," "project," "target," "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. Forward-looking statements in this release include,
among other things: guidance for 2019 and the first quarter of 2019 and the expectation that third party force majeure events should
be resolved by the end of February 2019. General risk factors include the availability, proximity and capacity of gathering, processing
and transportation facilities; the volatility and level of oil, natural gas, and natural gas liquids prices and related differentials, including
any impact on the Company’s asset carrying values or reserves arising from price declines; uncertainties inherent in projecting future
timing and rates of production or other results from drilling and completion activities; the imprecise nature of estimating oil and natural
gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results; the uncertain nature of joint
venture or similar efforts and of expected benefits from the actual or expected joint venture or similar efforts; the availability of
additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary
financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of
drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk
management strategy; and other such matters discussed in the Risk Factors section of SM Energy’s most recent Annual Report on
Form 10-K, as such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities
and Exchange Commission. The forward-looking statements contained herein speak as of the date of this announcement. Although
SM Energy may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except
as required by securities laws.
non-GAAP financial measures: See Appendix for reconciliations
non-GAAP forward-looking metrics: See Appendix for definitions
PREMIER OPERATOR OF TOP TIER ASSETS
3
2018: ANOTHER YEAR OF OUTSTANDING EXECUTION
Permian Production
Growth(1)(2)
+97%
Operating Margin
Increase(1)
+66%
PV-10
Value Creation(1)(2)
+79%
Long-term Debt
Reduction(1)
-$325MM
Discretionary Cash Flow
Increase(1)
+53%
(1) 2018 compared to 2017
(2) Based on retained assets
PREMIER OPERATOR OF TOP TIER ASSETS2019 PLAN OBJECTIVES
4
2019 Plan based on $55/Bbl WTI oil / $3/MMBtu Henry Hub natural gas
Generate free cash flow in 2H191
Deliver ~20% production growth in
the Permian
2
Generate solid full cycle returns
from last $ spent per drilling unit
3
Maintain leverage at ~3 times
net debt: EBITDAX at YE19
4
2019 CAPITAL PROGRAM
5
FOCUS ON HIGH MARGIN GROWTH
• Permian: ~100 net wells drilled and completed
• Eagle Ford: ~28 net wells drilled and ~18 net wells completed; joint
venture to include 6 wells drilled and 12 wells completed at no capital cost
to the Company
90%
5%
5%
Total Capital Spend ~$1,000 – 1,070MM
Drilling and
Completion
Facilities
Other
80%
20%
D&C Budget
Permian
Eagle
Ford
EXPECTED CAPITAL SPEND REDUCTION > 20%(1)
(1) 2019 compared to 2018
-
10,000
20,000
30,000
40,000
50,000
2017 2018 2019e
Pro
du
cti
on
(M
bo
e)
Midland Basin Eagle Ford Sold
2017 – 2019 PLAN HIGHLIGHTS
6
TARGETING FREE CASH FLOW 2H19
EXPECTED MIDLAND PRODUCTION UP ~135% 2017-2019(1)
(1) Based on retained assets
7
Capital & Production FY 2019
Total Capital Spend ($MM)(2) (before acquisitions) $1,000 - $1,070
Total Production (MMBoe) 45 – 48
Total Production (MBoe/d) 123.3 – 131.5
Oil 43 – 44%
Costs
LOE ($/Boe) ~$5.00
Transportation ($/Boe) ~$4.25
Production and Ad Valorem taxes ($/Boe)(4% of pre-hedge revenue + ~$0.70)
~$2.00
G&A ($MM) – includes ~$20MM non-cash compensation
~$120
Exploration expense, including capitalized overhead ($MM)– before dry hole expense, all of which is included in capital
expenditure guidance
~$50
DD&A ($/Boe) ~$17.00
(1) As of February 20, 2019
(2) Total Capital Spend is a non-GAAP financial measure that is defined in the Appendix. The Company is unable to present a quantitative
reconciliation of this forward-looking, non-GAAP financial measure to the most comparable GAAP financial measure because components of
the calculations, such as potential acquisitions and changes in current assets and liabilities, are inherently unpredictable. Moreover,
estimating such GAAP measures with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could
not be accomplished without unreasonable effort.
2019 PLAN GUIDANCE(1)
>20%Expected Reduction in Capital
~20%Growth in Permian Production
• Proved reserves up 18%(1) on retained assets
• Net proved reserve additions were 188 MMBoe (excluding revisions), or 119 MMBoe (net of revisions)
• Proved reserve PV-10 of $5.1B(2)
• Solid production replacement
81) Year-end 2018 compared to year-end 2017; based on retained assets
2) PV-10 is a non-GAAP measure. See Appendix for reconciliation of PV-10 (Non-GAAP) to Standardized Measure (GAAP).
• 49% Proved Developed
• 35% oil, 44% natural gas, 21% NGLs
2018 PROVED RESERVES: ADDITIONS & REVISIONS503 MMBOE - UP 18%(1); PV-10 UP 79%(1)(2)
Note: Calculated in accordance with SEC Pricing at $65.56 per barrel of oil NYMEX, $3.10 per MMBtu of
natural gas at Henry Hub and $33.45 per barrel of natural gas liquids (“NGLs”) at Mt. Belvieu.
40
44
188
503468
69
0
100
200
300
400
500
600
YE17 Divestitures Production Adds/Infills
Revisions YE18
Pro
ve
d R
ese
rve
s (
MM
Bo
e)
9
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
0
100
200
300
400
500
600
2016 2017 2018
PV
-10
(1)
($M
M)
Pro
ve
d R
es
erv
es
(M
MB
oe
)
Proved Reserves (on retained assets) Proved Reserves (sold) PV-10 (on retained assets)
PV-10
$5.1B
PV-10
$2.8B
PV-10
$0.8B
PROVED RESERVES AND PV-10(1)
YE 2016 – YE 2018
1) PV-10 is a non-GAAP measure. See Appendix for reconciliation of PV-10 (Non-GAAP) to Standardized Measure (GAAP).
PORTFOLIO TRANSITION - BUILDING VALUE
10
MIDLAND BASIN: NEW WELL RESULTS
MIDLAND
MARTIN HOWARD
UPTON
RockStar
Sweetie Peck
GREAT RESULTS - NEW MIDLAND WELLS AVG 1,417 BOE/D, 89% OIL (10,523’ LL)
B i g I r o n
C o y o t e Va l l e y
S i g n a l M o u n t a i n
18 Wells30 Day Avg. Peak Rate:
1,478 Boe/d | (89% oil)
3 Wells30 Day Avg. Peak Rate:
1,494 Boe/d | (90% oil)
8 Wells30 Day Avg. Peak Rate:
1,212 Boe/d | (89% oil)
S w e e t i e P e c k
7 Wells30 Day Avg. Peak Rate:
1,463 Boe/d | (87% oil)
Big
Iron
Coyote
Valley
Signal
Mountain
0
50,000
100,000
150,000
200,000
250,000
0 30 60 90 120 150 180 210 240 270 300 330 360
Cu
mu
lati
ve
Pro
du
cti
on
(B
oe
)
Days on Production
Previously Reported Well Avg New Well Avg
MIDLAND BASIN: ROCKSTAR NEW WELL RESULTS
11
SM AMONG RSEG IDENTIFIED TOP 4 PERMIAN PERFORMERS YTD(1)
(2) (3)
As of February 12, 2019
(1) RS Energy Group 7/9/18 - Ryan Luther, Latest Permian Well Performance – Who are the True Leaders?
(2) Previously Reported Well Average includes all (104) previously reported SM operated wells on production since 11/3/2016.
(3) New Well Average includes 29 new wells that have not been previously reported.
BIG NEW WELLS SUPPORT CONTINUED TOP TIER PERFORMANCE
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
1.1
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecS
an
d C
os
t In
de
xIn
de
xe
d to
No
rth
ern
Wh
ite
–Ja
n 1
8
12
COMPLETIONS EFFICIENCY AND LOCAL SAND USAGE
MIDLAND BASIN: DRIVING CAPITAL EFFICIENCY
Percent Improvement in
Stages Pumped Per Day Since 3Q16
Current Sand Costs(1)
Indexed to January 2018
-20%
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18
Pe
rce
nt
Imp
rove
me
nt
(1) Excludes last mile logistics as there is variability in these charges among vendors.
Maximizing local sand usage >150% improvement since 3Q16
13
MIDLAND BASIN 2019 PLANFOCUSED ON EXECUTION AND RETURNS ACROSS OUR TOP TIER ASSETS
MIDLAND
MARTIN
HOWARD
UPTON
RockStar
Sweetie Peck
~82,000N E T A C R E S
Rigs Currently Running:
Completion Crews:
2 0 1 9 P l a n O b j e c t i v e s
O p e r a t i n g D e t a i l s
OPTIMIZE RETURNS PER DEVELOPMENT UNIT
• Co-development of multiple intervals
• Maximize use of local sand
2019 PLAN DETAILS
• Deliver nearly 20% production growth
• Test Wolfcamp D and Dean
• ~100 net completions
• ~10,300’ average lateral feet per well
• ~770’ average spacing within zone
• $7.7MM average well cost
• ~47% Boe PDP decline (YE18 – YE19)
YE 2018 INVENTORY: 12 – 16 YEARS
14
DIFFERING DECLINE PROFILES OF LS & WCA WELLSSIMILAR RETURNS LS & WCA: SLOWER RAMP UP BUT SHALLOWER & LESS CAPEX
0%
20%
40%
60%
80%
100%
120%
1 9
17
25
33
41
49
57
65
73
81
89
97
105
113
121
129
137
145
153
161
169
177
185
% o
f IP
DAYS
JESTER WCA (BOPD/IP24HR) JESTER LS (BOPD/IP24HR)
Jester Pad Wells
0%
20%
40%
60%
80%
100%
120%
1
12
23
34
45
56
67
78
89
100
111
122
133
144
155
166
177
188
199
210
221
232
243
254
265
% o
f IP
DAYS
PAPAGIORGIO WCA (BOPD/IP24HR)
PAPAGIORGIO LS (BOPD/IP24HR)
Papagiorgio Pad Wells
2019 Plan composed of 36% Lower Spraberry wells
vs. 9% in 2018
% OF PEAK INITIAL PRODUCTION (IP) RATES VS TIME% OF PEAK INITIAL PRODUCTION (IP) RATES VS TIME
SOUTH TEXAS: AUSTIN CHALKHIGHER LIQUID CONTENT = HIGHER RETURNS
15
Galvan Ranch C 917H
7,886’ Lateral
30-day IP rate 2,084 Boe/d (3-stream)
Austin Chalk
Upper Eagle Ford
Lower Eagle Ford
Buda
625’
312.5’312.5’312.5’550’
917
625’
312.5’
10
100
1,000
10,000
7/5/2018 8/5/2018 9/5/2018 10/5/2018 11/5/2018 12/5/2018 1/5/2019
Pro
du
cti
on
Ra
te (
MC
FD
, B
PD
)
Production Date
Dry Gas Condensate NGL
AC Partial Penetration
ProducingGalvan Ranch C 917H
AC Target – waiting on
flowbackAC Target – 2019 drill plan
Well shut-in for tubing installation
ENHANCING INVENTORY VALUE
• Demonstrate value enhancement from new Eagle Ford
wells with longer laterals and wider spacing
• Further test the Austin Chalk
• Execute Phase 2 program of joint-venture in North Area
2019 PLAN DETAILS
• ~28 net drilled; ~18 net completions
• ~11,570’ average lateral feet per well
• ~1,040’ average spacing within zone
• $6.9MM average well cost
• ~29% Boe PDP decline (YE18 – YE19)
YE 2018 INVENTORY: 12 – 14 YEARS
SOUTH TEXAS 2019 PLANFOCUSED ON VALUE ENHANCEMENT AND RETURNS ACROSS TOP TIER ASSETS
~163,000
North
Area
East
Area
South
Area
WEBB COUNTY
DIMMIT COUNTY
N E T A C R E S
Rigs Currently Running:
Completion Crews:
O p e r a t i n g D e t a i l s
2 0 1 9 P l a n O b j e c t i v e s
16
MIDLAND BASIN WELL RESULTSSM RANKS #1 IN WELL PRODUCTIVITY IMPROVEMENT(1)
(1) BMO Capital Markets Research, January 2019. Data represents first nine months of 2018 and 2017. 17
W e l l P r o d u c t i v i t y I m p r o v e m e n t
Ye a r o v e r Ye a r
-40%
-30%
-20%
-10%
0%
10%
20%
30%
We
ll P
rod
uc
tivit
y –
Mid
lan
d B
as
in
Bo
e2
0:1
/ft
18
• Regularly engage with local community leaders to identify
and address key concerns related to our operations
• Board annually establishes environmental, health and safety
(EHS) performance goals, which are reviewed quarterly and
impact STIP payout
• Achieved a 0 Total Recordable Incident Rate (TRIR) for
employees per 200,000 man hours in 2017; contractor TRIR
was 0.53, lowest level achieved since 2011
• Implement a Spill Reduction Planning effort in each region,
which generally goes beyond current EPA requirements
• Disclose information using the GRI Framework
• Member of the API Environmental Partnership
BUILDING THE RIGHT CULTURE
SM
ENERGY
CORE
VALUES
Conduct
business with the
highest ethical
standard
Protect the health
and safety of our
employees,
contractors, and
neighbors
Protect the
environment and
be a good
steward of natural
resources
Support the
communities
where we live,
work and operate
Provide a
rewarding and
productive work
experience for
our employees
COMMITMENT TO ETHICAL OPERATIONS AND CORE VALUES
2017
Inaugural
CSR report
Responsible Stewardship
We are committed to honoring our core values, including conducting our business with ethics
and integrity and in compliance with applicable laws and regulations
Appendix
19
Fourth Quarter and
Full Year Performance
20
4TH QUARTER AND FULL YEAR 2018 PERFORMANCE
21
BIG CASH FLOW GROWTH
Production & Pricing 4Q18 2018
Total Production (MMBoe / MBoe/d) 11.3/122.8 43.9/120.3
Oil Percentage 45% 43%
Pre-Hedge Realized Price ($/Boe) $34.74 $37.27
Post-Hedge Realized Price ($/Boe) $31.74 $34.18
Costs $/Boe $/Boe
LOE $4.98 $4.74
Ad Valorem $0.39 $0.48
Transportation $4.19 $4.36
Production Taxes $1.19 $1.52
Production Expenses $10.75 $11.10
Cash Production Margin (pre-hedge) $23.99 $26.17
G&A – Cash $2.27 $2.23
G&A – Non Cash $0.42 $0.42
Operating Margin (pre-hedge) $21.30 $23.52
DD&A $16.10 $15.15
(1) Discretionary cash flow, Adjusted EPS, and Adjusted EBTIDAX are non-GAAP financial measures.
See Appendix for reconciliation of these non-GAAP measures.
(2) 2018 compared to 2017
$756.6 MMDiscretionary
Cash Flow(1)
2018
> 50% increase(2)
Earnings 4Q18 2018
EPS (Diluted) $2.73 $4.48
Adjusted EPS(1) $(0.18) $0.03
Adjusted EBITDAX(1) ($MM) $209.2 $900.4
$23.52Operating Margin
2018
> 65% increase(2)
22
Benchmark Pricing
NYMEX WTI Oil ($/Bbl) $58.81
NYMEX LLS Oil ($/Bbl) $66.78
NYMEX Henry Hub Gas ($/MMBtu) $3.64
Hart Composite NGL ($/Bbl) $29.91
Production Volumes Eagle Ford(1) Permian Total
Oil (MBbls) 303 4,789 5,091
Gas (MMcf) 18,569 6,910 25,480
NGL (MBbls) 1,956 6 1,962
MBoe 5,353 5,947 11,300
Revenue (in thousands)
Oil $16,456 $234,488 $250,943
Gas 65,839 28,630 94,468
NGL 46,936 183 47,119
Total $129,230 $263,301 $392,531
Expenses (in thousands)
LOE $14,150 $42,111 $56,261
Ad Valorem 2,497 1,893 4,390
Transportation 47,280 51 47.331
Production Taxes 486 12,982 13,468
Per Unit Metrics:
Realized Oil per Bbl $54.37 $48.97 $49.29
% of Benchmark - WTI 92% 83% 84%
Realized Gas per Mcf $3.55 $4.14 $3.71
% of Benchmark – NYMEX HH 98% 114% 102%
Realized NGL per Bbl $24.00 nm $24.01
% of Benchmark – HART 80% nm 80%
Realized per Boe $24.14 $44.28 $34.74
LOE per Boe $2.64 $7.08 $4.98
Transportation per Boe $8.83 $0.01 $4.19
Ad Val per Boe $0.47 $0.32 $0.39
Production Tax - per BOE/% of Pre-Hedge Revenue $0.09/0.4% $2.18/4.9% $1.19/3.4%
Production Margin per Boe $12.11 $34.69 $23.99
Note: Totals may not calculate due to rounding and other classifications.
(1) Includes nominal amounts of other production and expenses from the region.
4Q18 REALIZATIONS BY REGION
Simplified
Portfolio:2 Top Tier
Areas of Operation
$34.69Permian Production
Margin
2018 PROVED RESERVES BY REGION
231) Adjusted to show retained assets only
YE 2017(1) (MMBoe) 270.1 156.5 426.6
YE 2018South
TexasPermian Total
Oil (MMBbl) 16.3 159.4 175.7
Gas (Bcf) 993.4 328.4 1,321.8
NGL (MMBbl) 107.2 0.2 107.4
Total (MMBoe) 289.1 214.3 503.4
% Proved Developed 55% 40% 49%
Reserve growth 7% 37% 18%
2018 ACTIVITY BY REGION
24
WELLS DRILLED, FLOWING COMPLETIONS, AND DUC COUNT
Wells Drilled Flowing Completions DUC Count
4th Quarter 2018 2018 YTD 4th Quarter 2018 2018 YTDAs of December 31,
2018
Region Gross Net Gross Net Gross Net Gross Net Gross Net
Permian
Sweetie Peck 3 2 15 13 4 4 19 16 5 4
RockStar 24 20 111 104 18 18 95 88 56 51
Permian total 27 22 126 117 22 22 114 104 61 55
Eagle Ford(1) 7 3 36 20 14 7 40 26 29 23
Subtotal Operated Wells 34 25 162 137 36 29 154 130 90 78
Non-operated Wells(2) n/a - n/a - n/a - n/a 1 n/a -
Total n/a 25 162 137 36 29 154 131 90 78
As of December 31, 2018
(1) 2018 YTD net wells were adjusted for JV phase 2 contract terms. During 2018, there were 18 gross JV wells drilled and 16 JV wells
completed. As of December 31, 2018, there were 6 gross JV DUCs.
(2) Non-operated activity relates to wells located in the Permian Basin.
LEASEHOLD SUMMARY
25
RegionNet Acres(1)
12/31/2018
Midland Basin
RockStar 64,870
Sweetie Peck(2) 16,850
Midland Basin Total 81,720
Eagle Ford(3) 162,990
Rocky Mountain Other(4) 173,980
Other Areas/Exploration 26,385
Total 445,075
(1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of December 31, 2018.
(2) Sweetie Peck acreage includes 1,885 net drill-to-earn acreage.
(3) Approximately 1,500 net acres from the area were reclassified to Other Areas/Exploration.
(4) Rocky Mountain Other includes non-core Williston Basin, and other non-core acreage located in North Dakota, Montana, Wyoming, and Utah.
BALANCE SHEET OFFERS FINANCIAL FLEXIBILITY
26
LIQUIDITY OF $1.1B(1); NO NEAR-TERM MATURITIES
$500$500$500$500$476.8
$172.5 $0
$250
$500
$750
$1,000
$1,250
$1,500
$1,750
202720262025202420232022202120202019
Debt Maturities(2)
(in millions)
$0 drawn
Borrowing Base: $1.5B
Commitments: $1.0B
Coupon 1.500% 6.125% 5.000% 5.625% 6.750% 6.625%
Yield to worst(2) - 5.73% 6.01% 6.50% 7.05% 7.04%
Initial call date - 11/2018 7/2018 6/2020 9/2021 1/2022
Initial call price - 103.06% 102.50% 102.81% 103.38% 104.97%
(1) As of December 31, 2018
(2) Debt maturities as of December 31, 2018; YTW as of February 15, 2019
(3) Net Debt and Adjusted EBITDAX are non-GAAP financial measures. See Appendix for definition of Net Debt:TTM (trailing
twelve month) Adjusted EBITDAX (non-GAAP) and reconciliation of TTM Adjusted EBITDAX to GAAP net income.
• Redeemed $345 million principal outstanding 6.5% senior notes due 2021
• Extended ~$480MM in near-term maturities to 2027
• Net debt:TTM Adjusted EBITDAX(3) 2.9 times
27
NGL REALIZATIONS
• SM NGL price realizations are predominantly tied to Mont Belvieu, fee
based contracts
• Differential reflects NGL barrel product mix, transportation and fractionation
fees
53%
21%
7%
7%12%
SM Typical NGL Bbl(1)
Ethane Propane
Isobutane Normal Butane
Natural Gasoline
4Q17 1Q18 2Q18 3Q18 4Q18
Mt. Belvieu ($/Bbl) $32.12 $30.87 $33.10 $37.97 $29.91
SM Realization
($/Bbl)$26.01 $25.53 $27.55 $30.77 $24.01
% Differential to
Mt. Belvieu81% 83% 83% 81% 80%
(1) Reflects ethane processing; if the Company elects not to process ethane, the typical NGL barrel would consist of 42%
ethane, 27% propane, 13% natural gasoline, 9% normal butane, and 9% isobutane. During 2018, the Company
elected to process ethane in May, July, and August through November. During 2019, the Company has elected to
process ethane in January and February.
2019 Plan Activity & Hedges
28
Midland Basin 3 3 4 4 4 4 3 2 2 2 2 2
Eagle Ford(1) 1 2 2 - 1 - - - - - - -
-
20
40
60
80
100
-
2
4
6
8
10
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
To
tal N
et
DU
Cs
Op
era
ted
Rig
s
Midland Basin Eagle Ford Eagle Ford JV Total Net DUCs
29
2019 PLANNED RIG ACTIVITY AND COMPLETIONS BY MONTH
Completion Crews
(1) Excludes 1 completion crew in April and June through August related to the Eagle Ford JV.
WELL HEDGED
30
PERCENTAGE OF EXPECTED PRODUCTION HEDGED
Production Hedged(1)
~70%
~60%
Midland-Cushing Basis Swaps
• ~70% of expected 2019 production
volumes hedged
• ~70% oil volumes
• ~65% gas volumes
• (NGLs hedged by product)
• ~60% of expected Permian oil production
covered by basis hedges at ~$3.55/Bbl
Note: Hedging data as of February 18, 2019; all percentages calculated using mid-point of guidance.
(1) Percentage includes oil swaps and collars, natural gas swaps and collars, and NGL swaps; does not include basis swaps.
OIL AND GAS DERIVATIVE POSITIONS
31
BY QUARTER THROUGH 2020
Midland - Cushing
Oil Swaps Oil Collars Oil Basis Swaps
Period
Volume
(MBbls) $/Bbl(1)
Volume
(MBbls)
Ceiling
$/Bbl(1)
Floor
$/Bbl(1)
Volume
(MBbls)
Price
Differential
$/Bbl(1)
1Q’19 826 $60.16 2,503 $64.32 $51.66 2,433 ($4.44)
2Q’19 575 $55.52 2,802 $64.61 $52.18 2,571 ($4.49)
3Q’19 1,217 $61.41 2,364 $62.67 $49.07 3,291 ($2.86)
4Q’19 1,115 $59.97 2,386 $62.65 $49.08 3,338 ($2.87)
1Q’20 610 $67.09 290 $66.47 $55.00 3,388 ($1.00)
2Q’20 597 $66.04 297 $66.50 $55.00 2,792 ($1.04)
3Q’20 676 $65.28 294 $66.47 $55.00 2,756 ($1.05)
4Q’20 608 $64.36 284 $66.43 $55.00 2,665 ($1.05)
Note: Includes derivative contracts for settlement at any time during the first quarter of 2019 and later periods through 2020, entered into as of 2/18/19.
Excludes gas swaps related to volumes settling against IF WAHA and GD WAHA.
(1) Prices are weighted averages; natural gas prices reflect the weighted average of regional contract
positions and are no longer adjusted to a NYMEX equivalent.
Gas Swaps Gas Collars
Period
Volume
(BBTU) $/MMBTU(1)Volume
(BBTU)
Ceiling
$/MMBTU(1)
Floor
$/MMBTU(1)
1Q’19 19,805 $2.99 - - -
2Q’19 10,439 $2.82 4,358 $2.83 $2.50
3Q’19 12,531 $2.82 5,066 $2.83 $2.50
4Q’19 14,433 $2.88 4,818 $2.83 $2.50
1Q’20 9,123 $2.98 - - -
2Q’20 - - - - -
3Q’20 - - - - -
4Q’20 - - - - -
NGL DERIVATIVE SWAP POSITIONS(1)
32
OPIS MT. BELVIEU
Ethane Purity
Period
Volume
(MBbls) $/Bbl(2)
1Q’19 853 $12.25
2Q’19 877 $12.29
3Q’19 907 $12.34
4Q’19 896 $12.36
2019 Total 3,533
1Q’20 275 $11.13
2Q’20 264 $11.13
2020 Total 539
Propane
Period
Volume
(MBbls) $/Bbl(2)
1Q’19 540 $28.72
2Q’19 561 $31.32
3Q’19 637 $31.29
4Q’19 651 $31.64
2019 Total 2,389
Isobutane
Period
Volume
(MBbls) $/Bbl(2)
1Q’19 29 $35.70
2Q’19 29 $35.70
3Q’19 30 $35.70
4Q’19 29 $35.70
2019 Total 117
Natural Gasoline
Period
Volume
(MBbls) $/Bbl(2)
1Q’19 48 $50.93
2Q’19 49 $50.93
3Q’19 50 $50.93
4Q’19 50 $50.93
2019 Total 197
Normal Butane
Period
Volume
(MBbls) $/Bbl(2)
1Q’19 38 $35.64
2Q’19 38 $35.64
3Q’19 39 $35.64
4Q’19 39 $35.64
2019 Total 154
(1) Includes all NGL derivative contracts for settlement at any time during the first quarter of 2019 and later periods, entered into as of 2/18/19.
(2) Weighted-Average Contract Price
Fourth Quarter and Full Year 2018 Non-GAAP Reconciliations & Disclosures
33
TOTAL CAPITAL SPEND
34
RECONCILIATION TO COSTS INCURRED (GAAP)
Reconciliation of costs incurred in oil and gas
activities (GAAP) to total capital spend
(non-GAAP)(1)(3) (in millions)
Three Months Ended
December 31, 2018
Twelve Months Ended
December 31, 2018
Costs incurred in oil and gas activities (GAAP): $280.7 $1,389.5
Less:
Asset retirement obligations (4.2) (6.8)
Capitalized interest (4.9) (20.6)
Proved property acquisitions(2) (1.3) (1.3)
Unproved property acquisitions (7.7) (32.3)
Other (1.6) 0.6
Total capital spend (non-GAAP): $261.0 $1,329.1
(1) The non-GAAP measure of total capital spend is presented because management believes it provides useful information to investors for analysis of
SM Energy's fundamental business on a recurring basis. In addition, management believes that total capital spend 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. Total capital spend
should not be considered in isolation or as a substitute for Costs Incurred or other capital spending measures prepared under GAAP. The total capital
spend amounts presented may not be comparable to similarly titled measures of other companies.
(2) Includes approximately $0.3 million of ARO associated with proved property acquisitions for the year ended December 31, 2018.
(3) The Company completed several primarily non-monetary acreage trades in the Midland Basin during 2018 totaling $95.1 million of value attributed to
the properties surrendered. This non-monetary consideration is not reflected in the costs incurred or capital spend amounts presented above.
Note: Amounts may not calculate due to rounding
35
Reconciliation of net income (GAAP) and net cash
provided by operating activities (GAAP) to adjusted
EBITDAX (non-GAAP): (in thousands)
Three Months Ended
December 31, 2018
Twelve Months Ended
December 31, 2018Net income (GAAP) $309,732 $508,407
Interest expense 38,056 160,906
Interest income (596) (5,191)
Income tax expense 82,028 143,370
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 181,970 665,313
Exploration(2) 12,859 49,627
Abandonment and impairment of unproved properties 23,274 49,889
Stock-based compensation expense 6,228 23,908
Net derivative gain (411,136) (161,832)
Derivative settlement loss (33,892) (135,803)
Net gain on divestiture activity (1,261) (426,917)
Loss on extinguishment of debt 18 26,740
Other 1,901 1,977
Adjusted EBITDAX (non-GAAP) $209,181 $900,394
Interest expense (38,056) (160,906)
Interest income 596 5,191
Income tax expense (82,028) (143,370)
Exploration(2) (12,859) (49,627)
Amortization of debt discount and deferred financing costs 3,716 15,258
Deferred income taxes 81,036 141,708
Other, net 470 (1,690)
Net change in working capital 17,396 13,671
Net cash provided by operating activities (GAAP) $179,452 $720,629
1) Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property
abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other
items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably
estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally
generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios. In addition, adjusted EBITDAX is widely
used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published
research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating
activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX
amounts presented may not be comparable to similar metrics of other companies. Our credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants
that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our credit facility and would
therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures
governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.
2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary
from the amount shown on the statements of operations for the component of stock-based compensation expense recorded to exploration expense.
ADJUSTED EBITDAX(1)
RECONCILIATION TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)
36
Reconciliation of net income (GAAP) to adjusted net income
(loss) (non-GAAP):
(in thousands, except per share data)
Three Months Ended
December 31, 2018
Twelve Months Ended
December 31, 2018Net income (GAAP) $309,732 $508,407
Net derivative gain (411,136) (161,832)
Derivative settlement loss (33,892) (135,803)
Net gain on divestiture activity (1,261) (426,917)
Abandonment and impairment of unproved properties 23,274 49,889
Loss on extinguishment of debt 18 26,740
Other, net 1,901 2,777
Tax effect of adjustments(2) 91,378 139,997
Adjusted net income (loss) (non-GAAP) $(19,986) $3,258
Net income per diluted common share (GAAP) $2.73 $4.48
Net derivative gain (3.63) (1.43)
Derivative settlement loss (0.30) (1.20)
Net gain on divestiture activity (0.01) (3.76)
Abandonment and impairment of unproved properties 0.21 0.44
Loss on extinguishment of debt - 0.24
Other, net 0.02 0.02
Tax effect of adjustments(2) 0.80 1.24
Adjusted net income (loss) per diluted common share (non-GAAP) $(0.18) $0.03
Diluted weighted-average common shares outstanding (GAAP): 113,286 113,502
1) Adjusted net income (loss) excludes certain items that the Company believes affect the comparability of operating results. Items excluded generally are non-recurring items or are items
whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as derivative gains and losses net of settlements, impairments,
net (gain) loss on divestiture activity, materials inventory loss, and gains or losses on extinguishment of debt. The non-GAAP measure of adjusted net income (loss) 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 (loss) is widely used by professional research analysts and others as a performance measure 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 (loss) should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, cash provided by operating
activities, or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income (loss) excludes some, but not all, items that affect net income
(loss) and may vary among companies, the adjusted net income (loss) amounts presented may not be comparable to similarly titled measures of other companies.
2) The tax effect of adjustments is calculated using a tax rate of 21.7%, for the three-month and twelve-month periods ended December, 2018. Note that the rate used for the three-month
period ended March 31, 2018 was 21.9%. This rate approximates the Company's statutory tax rate adjusted for ordinary permanent differences.
Note: Amounts may not calculate due to rounding
ADJUSTED NET INCOME (LOSS)(1)
RECONCILIATION TO NET INCOME (GAAP)
DISCRETIONARY CASH FLOW
37
RECONCILIATION TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)
Reconciliation of net cash provided by operating
activities (GAAP) to discretionary cash flow
(non-GAAP)(1) (in millions)
Three Months Ended
December 31, 2018
Twelve Months Ended
December 31, 2018
Net cash provided by operating activities (GAAP): $179.5 $720.6
Net change in working capital (17.4) (13.7)
Exploration(2)(3) 12.9 49.6
Discretionary cash flow (non-GAAP): $175.0 $756.5
(1) Discretionary cash flow is defined as net cash provided by operating activities excluding changes in assets and liabilities, and exploration (included in
our capital spend guidance). Discretionary cash flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash
which is used to internally fund exploration and development activities, pay dividends, and service debt. Discretionary cash flow is presented because
management believes it provides useful information to investors when comparing our cash flows with the cash flows of other companies that use the
full cost method of accounting for oil and gas producing activities, or have different financing and capital structures or tax rates. Discretionary cash
flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as
defined by GAAP, or as a measure of liquidity, or an alternative to net income.
(2) Exploration expense is added back in the calculation of discretionary cash flow because, for peer comparison purposes, this number is included in our
reported total capital spend.
(3) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the statements of operations.
Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the statements of operations for the
component of stock-based compensation expense recorded to exploration expense.
Note: Amounts may not calculate due to rounding
PV-10
38
RECONCILIATION TO STANDARDIZED MEASURE (GAAP)
(1) The non-GAAP measure of PV-10 is presented because management believes it provides useful information to investors for analysis of SM Energy's
fundamental business on a recurring basis. In addition, management believes that PV-10 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. PV-10 should not be considered in isolation or as
a substitute for other measures prepared under GAAP.
Reconciliation of standardized measure (GAAP) to
PV-10 (non-GAAP)(1) (in millions)
As of
December 31, 2018
As of
December 31, 2017
Standardized measure of discounted future net cash flows (GAAP): $4,654.4 $3,024.1
Add: 10 percent annual discount, net of income taxes 3,847.1 2,573.2
Add: future undiscounted income taxes 1,012.2 205.7
Undiscounted future net cash flows 9,513.7 5,803.0
Less: 10 percent annual discount without tax effect (4,409.4) (2,746.5)
PV-10 (non-GAAP): $5,104.3 $3,056.5
PV-10 value of assets sold in 2018: n/a (207.3)
PV-10 pro-forma assets sold: $5,104.3 $2,849.2
39
DEFINITIONS AND RECONCILIATION OF NET DEBT : TTM ADJUSTED EBITDAX
The Company defines Net debt as the total principal value of outstanding senior notes, senior convertible notes plus balances
drawn on the revolving credit facility (also referred to as total funded debt) less cash and cash equivalents. The Company presents
this metric to help evaluate its capital structure and financial leverage and believes that it is widely used by professional research
analysts, including credit analysts, and others in the evaluation of total leverage.
Reconciliation of Net Debt
(in thousands) December 31,
2018
Senior Notes (principal value from Note 5 of Form 10-K) $ 2,476,796
Senior Convertible Notes (principal value from Note 5 of Form 10-K) 172,500
Revolving credit facility —
Total funded debt $ 2,649,296
Less: Cash and cash equivalents (77,965)
Net Debt $ 2,571,331
The Company defines Net debt-to-adjusted EBITDAX as Net Debt (defined above) divided by adjusted EBITDAX (reconciled on
previous slide) for the prior twelve-month period. The Company presents this metric to show trends that investors may find useful
in understanding the Company’s ability to service its debt. This metric is widely used by professional research analysts, including
credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. A variation of
this calculation is a financial covenant under the Company’s credit agreement for its revolving credit facility beginning in the fourth
quarter of 2018.
40
DEFINITION OF TOTAL CAPITAL SPEND
The Company defines Total capital spend as costs incurred, less ARO, capitalized interest and acquisitions. Total capital spend
is presented because management believes that it provides useful information to investors in the analysis of SM Energy and 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. Total capital spend should not be used in isolation or as a
substitute to costs incurred or other capital spending measures under GAAP. Total capital spend may not be comparable to
similarly titled measures of other companies. We are unable to provide a reconciliation of this forward-looking non-GAAP measure
to the most comparable GAAP financial measure because certain information needed to reconcile this measure is dependent on
future events, some of which are outside of the control of the Company. Moreover, estimating such GAAP measures with the
required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without
unreasonable effort.
Capital spend as reported for actual results is reconciled above to GAAP costs incurred in oil and gas activities.
41
RESERVES AND RESOURCES
The Securities and Exchange Commission (“SEC”) requires oil and natural gas companies, in their filings with the SEC, to disclose proved
reserves, which are those quantities of oil, natural gas and NGLs, 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
(using the trailing 12-month average first-day-of-the-month prices), 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, regardless of whether deterministic
or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible
reserves that meet SEC definitions for such reserves; however, the Company currently does not disclose probable or possible reserves in its
SEC filings.
In this presentation, proved reserves attributable to the Company at December 31, 2018, are estimated utilizing SEC reserve recognition
standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $65.56 per Bbl of oil, $3.10 per
MMBtu of natural gas, and $33.45 per Bbl of NGLs. At least 80% of the PV-10 of the Company’s estimate of its total proved reserves at
December 31, 2018, was audited by Ryder Scott Company, L.P. The Company may use the terms “economic resource,” “economic inventory,”
“additional resource” and similar phrases to describe estimates of gross drilling locations that the SEC rules may prohibit from being included in
filings with the SEC. These are the Company’s internal estimates of drilling locations. These quantities may not constitute “reserves” within the
meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules. Such estimates and identified drilling
locations may not have been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual
locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially from these estimates.
There is no commitment by the Company to drill all of these drilling locations.
The calculation of economic resources is not necessarily calculated in accordance with SEC guidelines for proved reserves and is not reviewed
by third party engineers. Economic resources presented in this presentation are calculated using benchmark pricing and projected pricing,
which differs from the pricing used for proved reserves. Management believes the presentation of economic resources and economic drilling
inventory are useful to investors in the valuation of SM Energy; however, the calculations may not be consistent with similar metrics provided by
peers.
