may 2017 investor presentation - cloud object …may+investor+presentation+v… · investor...
TRANSCRIPT
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,” “assume,” “believe,”
“budget,” “estimate,” “expect,” “forecast,” “guidance,” “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. Forward-looking statements in this presentation include, among other things,
2017 guidance, expectations regarding growth strategy, consummation of pending transactions, anticipated drilling plans and capital
expenditures, anticipated growth in cash flows, the expected benefits, financing sources and timing of acquisitions, and the expected benefits
and likelihood of completing divestitures. General risk factors include the uncertain nature of 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 uncertainty of negotiations to result in an agreement or a completed
transaction; the availability of and access to capital markets; the availability, proximity and capacity of gathering, processing and transportation
facilities; the volatility and level of oil, natural gas, and natural gas liquids prices, including any impact on the Company’s asset carrying values
or reserves arising from price declines; uncertainties inherent in projecting future rates of production or other results from drilling and completion
activities; the imprecise nature of estimating oil and gas reserves; uncertainties inherent in projecting future drilling and completion activities,
costs or results, including from pilot tests; 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 2016 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. In addition, production forecasts
and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells
and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost
increases. 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.
2
Non-GAAP financial measures: See appendix for reconciliations
Note: slide deck changes (slides 5,6, and 8) include impact of increased
production and cash flow to 3-year plan.
3
Midland BasinSweetie Peck/RockStar
~88,000 net acres
Maverick BasinEagle Ford
~167,000 net acres
SM Energy 3-Year Plan Focused on Two Core Assets
3
Top tier oil in Midland + top tier NGLs and gas in Eagle Ford
Successful transformation to core up portfolio
4
SM Energy A Premier Operator of Top Tier Assets
3 Year Plan Expected
Outcomes:
Big growth in
high-margin
production
Big growth in
cash flow
Debt:EBITDAX
~2x in 2019
Top Tier
portfolio
5
Big Expected Production Growth
0%
10%
20%
30%
40%
50%
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
2016 2017 2018 2019
Oil %
Pro
du
cti
on
(MB
oe
)
Midland Basin Operated Eagle Ford Rockies Revised Guidance Sold Oil %
(e) (e) (e)
~100% CAGR Midland Basin
Adjusted 3-year plan(1)
(1) Adjusted for increased production guidance provided on 5/3/17 and retention of Divide County assets.
(2) Sold production relates to the Non-operated Eagleford, Williston, and Southeast New Mexico divestitures. Note that the initial version of this slide posted on 5/16/17 only
included the Non-operated Eagle Ford divestiture in the sold category.
(2)
6
Big Cash Flow Growth Driven by Expected Margin Expansion
Operating margin expected to increase 80% 4Q16 – 2019
Production growth expected within cash flow in 2019
Adjusted plan results in increased cash flow, decreased outspend
Note: Based on strip pricing as of 2/3/17.
(1) Adjusted for increased production guidance provided on 5/3/17 and retention of Divide County assets.
(2) Realized price before the effect of hedges less LOE, transportation, production taxes, and G&A.
Cash Flow Expected to Double 2017 - 2019
$10
$13
$16
$19
$22
$25
$0
$650
$1,300
4Q16 2017 2018 2019
Op
era
tin
g M
arg
in$
/Bo
e
Ca
sh
Flo
w$
/MM
Cash Flow Operating Margin
(e)
Adjusted 3-year plan(1)
(e) (e)
(2)
Financial Discipline Strengthening the Balance Sheet
7
On track with 2017 financial strategy
Other
86% 8%
Drilling and
Completion
86%
Facilities
6%
Other
8%
(1)
• Liquidity of $1.6 billion (as of March 31, 2017)
• $747 million net cash proceeds from non-operated Eagle Ford sale March 2017
• Net debt reduced to $2.3 billion; reduced 22% 1Q17/4Q16
• No bond maturities until 2021; 2021 notes currently callable; 2023 notes callable July 2017
• Coverage metrics provide flexibility; March 31, 2017:
• Senior Secured Debt:TTM Adjusted EBITDAX at ~0.0 times; max ratio allowed 2.75 times
• TTM Adjusted EBITDAX:Interest at ~4.5 times; minimum ratio required 2.0 times
$500$500$500$395
$562
$345
$172.5
$0
$250
$500
$750
$1,000
2026202520242023202220212020201920182017
Debt Maturities as of March 31, 2017(in millions)
~$0 drawn
Commitments and Borrowing
base $925 million (as of 3/31/17)
Corporate ratings: S&P BB-, Moody’s B1
Coupon 1.500%
6.500%
6.125% 6.500% 5.000% 5.625% 6.750%
3-Year Plan Prefunded by Cash Flow and Divestiture
8
Proceeds from non-operated Eagle Ford sale > 2017-2018 expected outspend
Other
86% 8%86%
Facilities
6%
Other
8%Midland
Basin
80%
(2)(1)
2017
Outspend
2018
Outspend
Non-operated
Eagle Ford
sale
2017 – 2018
Projected
Outspend
• Additional cash flows from retention of Divide County assets reduce
2017-2018 expected outspend
• 3-year plan objective of Net Debt : EBITDAX ~2.0x
Note: Based on strip pricing as of 2/3/17.
Financial Discipline Hedging Provides Cash Flow Stability
9
• ~75% of expected 2017 production volumes hedged (at the midpoint of guidance)
• ~ 70% of oil, 80% of natural gas and 80% of NGLs
• Approximately 1/2 of expected 2018 volumes hedged
0
1
2
3
4
5
6
7
8
9
10
2Q17 3Q17 4Q17
(MM
BO
E)
Hedged Volumes as of April 26, 2017
Oil Gas NGLs
Credit Agreement modified to allow hedging of up
to 85% of 2017-2019 projected production
Note: The hedged volumes on this slide do not include any volumes related to basis swaps.
SM Energy A Premier Operator of Top Tier Assets
2017 Priorities:
Complete
portfolio
transition
Focus capital
on drivers of
value creation
Midland Basin
development
acceleration
Strong
balance sheet
and liquidity
10
Midland Basin Setting Up for Expanded 2018 Program
11
Excellent vendor relationships and continued improvements in operating efficiencies
set the stage for expansion in 2018
Significant experience
in the basin - strong
vendor relationships
Sufficient takeaway
capacity
Sufficient water
availability to run program
Continued performance
improvement
Midland Basin 1Q17
12
Midland Basin~88,000 net acres
Sweetie Peck
RockStar
Halff East
Ramping up quickly – setting up for 2018
• 6 horizontal rigs and 1 data
gathering rig; 3 completions crews
active
• Production up 55% sequentially;
RockStar wells significantly
outperforming acquisition
assumptions
• Drilled 20(1) 10,000’ laterals to date
and added 1,300 net acres of
adjacent land positions
• Program actively testing Wolfcamp
A, Wolfcamp B, and Lower
Spraberry
(1) Includes four wells drilled by previous operator and completed by SM.
Midland Basin Premier Operator
13
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
0 20 40 60 80 100 120 140 160 180 200 220 240
Cum
ula
tive P
roduction (
BO
E)
Days
VENKMAN 26-35 A #15WA VENKMAN 26-35 B #1 WA
Applying technology to optimize development
• Acquiring core and log data
Steering to best zones
Identifying new pay intervals
• Enhancing completion designs
• Swapping and acquiring adjacent
land positions: more long laterals
• Gaining efficiencies through intensive
pad drilling
• Using ‘Digital Oilfield’ to improve well
uptime statistics
Example: Venkman wells in RockStar Area
Improved
Completion
Design
• Optimized completion design in two
Wolfcamp A wells in same spacing unit
• Result: More than 60% improvement in
120 day cumulative oil production
(completed by previous operator)
7,700’ lateral7,430’ lateral
14
Howard County Significant Increase in Activity
Industry confidence drives increased drilling activity across the county
January 2017: 18 Rigs April 2017: 28 Rigs
15
Howard County Positive Peer Well Results
Peer wells extend “confirmed” geologic assessment to east and south
Tubb A 1HA
Thumper 14-23
• Thumper 14-23
• 7,500’ lateral
• 24-hour rate: 1,357 Boe
(91% oil)
• Tubb A 1HA
• 9,366’ lateral
• produced 141,000 Boe
over 132 days
Source: Tubb A 1HA well data courtesy of Earthstone Energy Inc.
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
220,000
240,000
0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320
Gro
ss
Cu
mu
lati
ve
Pro
du
cti
on
(B
OE
)
Production Days
1 MMBOE Peer Type Curve 20% IRR Type Curve
RockStar Top Tier Well Performance Continues
16
Initial production rates on SM completed wells soundly beating acquisition assumptions
Note: Well economics at $50 oil and $3.00 gas; monthly data normalized to days on production.
* Peer Type Curve adjusted to meet 20% IRR
SM Operated Well
RockStar wells average ~90% oil at ~40 API gravity
Howard County Recent Well Results
Recent wells targeting three intervals: Wolfcamp A, Wolfcamp B, and Lower Spraberry
17
Well Name Interval
Lateral
Length
IP Rate
(BOE/d)
IP
Days
Tackleberry 43-42 A 1LS LS 7,873’ 1,286 30
Tackleberry 43-42 A 1WA WCA 7,861’ 2,262 30
Tackleberry 43-42 A 2WB WCB 7,885’ 1,412 30
Rambo 3846WA(4) WCA 7,546’ 1,130 30
Rambo 3848WA(5) WCA 7,590’ 1,118 30
Venkman 26-35 B 1WA WCA 7,700’ 1,274 30
Top Gun 1632LS(6) LS 7,711’ 1,236 30
Top Gun 1652WA(7) WCA 7,595’ 1,655 30
(1) Name changed from Corrine Elizabeth 26-27 A 1H (4) Name changed from Rambo 38-47 7WA (7) Name changed from Top Gun 1H
(2) Name changed from Corrine Elizabeth 26-27 A 2H (5) Name changed from Rambo 38-47 9WA
(3) Name changed from Corrine Elizabeth 26-27 A 3H (6) Name changed from Top Gun 2H
Well Name Interval
Lateral
Length
IP Rate
(BOE/d)
IP
Days
Guitar North 2722LS(1) LS 9,692 1,093+ 20
Guitar North 2742WA(2) WCA 9,698 1,981 20
Guitar North 2762WB(3) WCB 9,693 1,693 20
1Q17 Wells
4Q16 Wells
Note: Guitar North 2722LS 20-day IP Rate still climbing
0
10
20
30
40
50
0 30 60 90 120 150 180 210 240 270
Gro
ss C
um
ula
tive P
roduction (
BO
E/F
T)
Production Days
Eagle Ford Increasing Value With More Wells Per Section
18
900’ East Type Curve
(LEF) – BOE/FT
All three areas support UEF/LEF co-development
6 Wells (A)
11 UEF/LEF
Co-Development
wells
4Q16
Completions
Operated Eagle Ford – Recent Well Results
2015/2016 East Area co-development
4Q 2016 East Area co-development (A)
1Q 2017 North Area co-development
South
Area
North
AreaEast
Area
East 4Q16 Completions
Continued Outperformance
at 312’ plan view spacing
1Q17
Completions
Note: 2-stream data; does not reflect ~70
Bbls/MMcf NGL yield for type curve shown.
19
SM Energy A Premier Operator of Top Tier Assets
3 Year Plan Expected Outcomes:
Big growth in
high-margin
production
Big growth in
cash flowDebt:EBITDAX
~2x in 2019
2017 Priorities:
Complete
portfolio
transition
Focus capital
on drivers of
value creation
Midland Basin
development
acceleration
Top Tier
portfolio
Strong
balance sheet
and liquidity
0%
20%
40%
60%
80%
100%
120%
$40 $45 $50 $55 $60
IRR
NYMEX WTI
7,600' 10,000'
0%
20%
40%
60%
80%
100%
120%
$40 $45 $50 $55 $60
IRR
NYMEX WTI
7,600' 10,000'
0%
20%
40%
60%
80%
100%
$0.60 $0.65 $0.70
IRR
Mt. Belvieu $/Gal
Regional Well Projected Economics
21
2017 capital program focusing on areas with top tier returns
RockStar – Wolfcamp A
Well Cost: $5.6MM
Well Spacing: 660’Well Cost: $6.8MM
Well Spacing: 660’Well Cost: $5.9MM
Well Spacing: 660’
Well Cost: $7.0MM
Well Spacing: 660’
Sweetie Peck – Lower Spraberry
Note: well costs include drill, complete, and equip; sensitivities at $3.00/MMBtu NYMEX; Eagle Ford East oil flat at $50/Bbl WTI
Eagle Ford East
Well Cost: $5.2MM, Lateral Length: 8,000’, Well Spacing: 625’, Sand Loading: 2,000 lbs/ft, Stage Spacing: 150’
Sand loading: 1,900 lbs/ft; Stage Spacing: 167’ Sand loading: 1,900 lbs/ft; Stage Spacing: 167’
Eagle Ford East
~35% NGLs
1Q17 Average
Mt. Belvieu ($/Gal)
1st Quarter 2017 Performance
22
Production 1Q17
Total Production (MMBoe) 12.1
Average Daily Production (MBoe/d) 134.4
Pre-Hedge Realized Price ($/Boe) $27.55
Post-Hedge Realized Price ($/Boe) $27.55
Costs
LOE ($/Boe) $3.82
Ad Valorem ($/Boe) $0.55
LOE including Ad Valorem ($/Boe) $4.37
Transportation ($/Boe) $5.88
Production Taxes (% of pre-derivative oil, gas & NGL revenue) 4.2%
Total Cash Production Expenses $11.42
Production Margin (pre-hedge) $16.13
G&A – Cash ($/Boe) $2.08
G&A – Non Cash ($/Boe) $0.34
Total G&A ($/Boe) $2.42
DD&A ($/Boe) $11.39
1Q17 Regional Realizations
23
Pricing
NYMEX WTI Oil ($/Bbl) $51.91
NYMEX LLS Oil ($/Bbl) $53.39
NYMEX Henry Hub Gas ($/MMBTU) $3.32
Hart Composite NGL ($/Bbl) $26.74
Production Volumes Eagle Ford Op(1) Rocky Mountain Permian
Eagle Ford
Non-Op(2) SM Total
Oil (MBbls) 421 999 1,623 483 3,525
Gas (MMcf) 26,936 1,026 2,882 3,052 33,895
NGL (MBbls) 2,404 36 6 474 2,921
MBOE 7,315 1,206 2,109 1,465 12,095
Expenses (in thousands)
LOE $13,420 $11,785 $16,328 $4,629 $46,162
Ad Valorem 3,172 32 2,174 1,285 6,663
Transportation 58,366 2,288 116 10,323 71,093
Production Taxes 3,389 4,974 4,617 1,148 14,128
Revenue (in thousands)
Oil $17,324 $47,261 $81,499 $21,540 $167,624
Gas 77,983 1,641 11,309 10,218 101,151
NGL 53,152 919 147 10,205 64,423
Total $148,459 $49,821 $92,955 $41,962 $333,198
Note: Totals may not sum due to rounding and other classifications
(1) Includes nominal amounts of other production and expenses from the region
(2) The Eagle Ford Non-Op divestiture closed on March 10, 2017
Per Unit Metrics:
Realized Oil/Bbl $41.13 $47.33 $50.22 $44.61 $47.55
% of Benchmark - WTI 79% 91% 97% 86% 92%
Realized Gas/Mcf $2.90 $1.60 $3.92 $3.35 $2.98
% of Benchmark – NYMEX HH 87% 48% 118% 101% 90%
Realized NGL/Bbl $22.11 $25.19 $24.15 $21.54 $22.06
% of Benchmark – HART 83% 94% 90% 81% 82%
Realized BOE $20.30 $41.31 $44.07 $28.64 $27.55
LOE/BOE $1.83 $9.77 $7.74 $3.16 $3.82
Ad Val/BOE $0.43 $0.03 $1.03 $0.88 $0.55
Transportation/BOE $7.98 $1.90 $0.06 $7.05 $5.88
Production Tax - % of
Pre-Hedge Revenue
2.3% 10.0% 5.0% 2.7% 4.2%
2017 Activity Wells Drilled, Flowing Completions & DUC Count
24(1) Activity in the Powder River Basin is funded entirely through a carry arrangement with a third party.
Wells Drilled Flowing Completions DUC Count
1st Quarter 2017 1st Quarter 2017 1st Quarter 2017
Region Gross Net Gross Net Gross Net
Permian
Sweetie Peck 7 7 11 11 7 7
RockStar 12 12 5 5 13 13
Permian total 19 19 16 16 20 20
Eagle Ford (operated) 5 5 17 17 35 35
Rocky Mountain
Divide County - - - - 20 17
Powder River Basin(1) 3 - 1 - 3 -
Rocky Mountain total 3 - 1 - 23 17
Subtotal Operated Wells 27 24 34 33 78 72
Non-operated Wells n/a 2 n/a - n/a 2
Total n/a 26 n/a 33 n/a 74
Leasehold Summary
25
As of March 31, 2017
Net Acres(1)
3/31/17
Midland Basin
Sweetie Peck(2) 15,880
Halff East (Upton County) 5,985
RockStar 66,195
Eagle Ford
Operated 166,760
Rocky Mountain
Divide 123,570
Powder River Basin 156,260
Rocky Mountain Other(3) 190,330
Other Areas/Exploration 24,915
Total 749,895
(1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of March 31, 2017. RockStar
acreage includes approximately 900 net acres related to transactions that closed subsequent to March 31, 2017.
(2) Sweetie Peck acreage includes 1,480 net acres of drill-to-earn acreage.
(3) Rocky Mountain Other includes non-core acreage located in North Dakota, Montana, Wyoming, and Utah.
Adjusted EBITDAX Reconciliation
26
Reconciliation of net income (GAAP) to Adjusted EBITDAX (non-GAAP) to
net cash provided by operating activities (GAAP): (in thousands)
Three Months Ended
March 31, 2017Net income (GAAP) $74,434
Interest expense 46,953
Other non-operating income, net (335)
Income tax expense 44,506
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 137,812
Exploration(1) 10,570
Stock-based compensation expense 5,455
Net derivative gain (114,774)
Derivative settlement gain 7
Net gain on divestiture activity (37,463)
Loss on extinguishment of debt 35
Other 4,986
Adjusted EBITDAX (Non-GAAP) 172,186
Interest expense (46,953)
Other non-operating income, net 335
Income tax expense (44,506)
Exploration(1) (10,570)
Amortization of discount and deferred financing costs 4,946
Deferred income taxes 33,225
Plugging and abandonment (1,191)
Other, net (432)
Changes in current assets and liabilities 27,926
Net cash provided by operating activities (GAAP) $134,966
Note: Adjusted EBITDAX represents net income (loss) before interest expense, other non-operating income and expense, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration
expense, property impairments, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, gains and losses on divestitures, gains or losses on extinguishment of debt, and
materials inventory impairments and losses on sale. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing
and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes it provides useful additional information to investors and analysts, 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 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 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. Under the terms of the Company’s credit agreement, if the Company fails to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a
minimum permitted ratio of adjusted EBITDAX to interest, it will be in default, an event that would prevent it from borrowing under its credit facility and would therefore materially limit the Company’s sources of liquidity. In addition, if the Company was
in default under its credit facility and unable to obtain a waiver of that default from its lenders, the lenders under that facility and under the indentures governing the Company’s outstanding Senior Notes and Senior Convertible Notes would be entitled
to exercise all of their remedies for a default.
(1) 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 expense.
Adjusted Net Loss Reconciliation
27
Note: 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, gains and losses
on divestiture activity, and materials inventory loss. The non-GAAP measure of adjusted net 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 loss 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 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 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.
(1) Income taxes are calculated using a tax rate of 36.1%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. The rate is applied to the adjustments made in calculating adjusted net loss.
(2) For periods where the Company reports net income (GAAP) and adjusted net loss (non- GAAP), basic weighted-average common shares outstanding are used in the calculation of adjusted net loss per diluted common share.
Reconciliation of net income (GAAP) to adjusted net loss (non-GAAP):
(in thousands, except per share data)
Three Months Ended
March 31, 2017Net income (GAAP) $74,434
Net derivative gain (114,774)
Net gain on divestiture activity (37,463)
Other, net 5,028
Tax effect of adjustments(1) 53,142
Adjusted net loss (Non-GAAP) $(19,633)
Diluted net income per common share (GAAP) $0.67
Net derivative gain (1.03)
Net gain on divestiture activity (0.34)
Other, net 0.04
Tax effect of adjustments(1) 0.48
Adjusted net loss per diluted common share (Non-GAAP)(2) $(0.18)
Basic weighted-average common shares outstanding: 111,258
Diluted weighted-average common shares outstanding: 111,329
Total Capital Spend Reconciliation
28
Reconciliation of Costs Incurred in Oil and Gas Activities (GAAP)
to Total Capital Spend (Non-GAAP)(1) (in millions)
Three Months
Ended
March 31, 2017
Costs incurred in oil and gas activities (GAAP): $281.5
Less: Asset retirement obligation (0.9)
Less: Capitalized interest (2.2)
Less: Proved property acquisitions(2) (2.2)
Less: Unproved property acquisitions(3) (83.6)
Less: Other 0.3
Total capital spend (Non-GAAP): $192.9
(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 $800,000 of ARO associated with proved property acquisitions for the three month period ended March 31, 2017.
(3) Includes approximately $24.5 million related to the fair value attributed to the properties surrendered in the non-monetary acreage trade that
completed during the three-month period ended March 31, 2017.
Derivative Positions Summary By Quarter Through 2018
29
As of April 26, 2017
Period
Volume
(MBbls) $/Bbl(1)
Volume
(BBTU) $/MMBTU(1)
Volume
(MBbls) $/Bbl(2)
2Q’17 1,444 $46.44 26,205 $3.98 2,114 $21.40
3Q’17 1,340 $46.66 23,657 $4.01 2,019 $20.89
4Q’17 1,254 $46.35 22,001 $3.98 1,996 $20.18
1Q’18 - - 19,628 $3.25 1,828 $21.45
2Q’18 - - 13,052 $2.85 1,438 $16.26
3Q’18 - - 14,241 $2.87 1,414 $16.53
4Q’18 - - 15,487 $2.90 1,416 $16.72
Period
Volume
(MBbls)
Ceiling
$/Bbl(1)
Floor
$/Bbl(1)
2Q’17 636 $54.10 $45.00
3Q’17 583 $54.05 $45.00
4Q’17 1,086 $56.05 $47.51
1Q’18 1,026 $58.46 $50.00
2Q’18 1,004 $58.37 $50.00
3Q’18 1,393 $57.93 $50.00
4Q’18 1,607 $57.75 $50.00
Fixed Swaps
Collars
Oil
Oil
Gas NGL(3)
(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.
(2) Weighted Average Price – Mont Belvieu
(3) NGL derivative positions include propane, ethane, gasoline, and butanes.
Note: Includes all commodity derivative contracts for settlement at any time during the second quarter of 2017 and later periods through 2018, entered into as of 4/26/17.
Period
Volume
(MBbls)Price Differential
$/Bbl(1)
2Q’17 - -
3Q’17 566 ($1.62)
4Q’17 1,403 ($1.55)
1Q’18 1,075 ($1.40)
2Q’18 1,371 ($1.42)
3Q’18 1,609 ($1.43)
4Q’18 1,609 ($1.43)
Midland – Cushing Oil Basis Swaps
NGL Derivative Position Detail(1)
30
Period
Volume
(MBbls) $/Bbl(2)
2Q’17 892 $9.11
3Q’17 906 $9.48
4Q’17 966 $9.65
2017 Total 2,764
1Q’18 923 $10.90
2Q’18 915 $10.87
3Q’18 878 $10.76
4Q’18 875 $10.82
2018 Total 3,591
NGL Swaps OPIS Eth Purity Mt Belv NGL Swaps OPIS Propane Mt Belv Non-TET NGL Swaps Natural Gasoline Mt Belv Non TET
NGL Swaps OPIS IsoButane Mt Belv Non TETNGL Swaps OPIS NButane Mt Belv Non TET
(1) Includes all commodity derivative contracts for settlement at any time during the second quarter of 2017 and later periods through 2018 entered into as of April 26, 2017.
(2) Weighted-Average Contract Price
Note: Totals may not sum due to rounding; reference 10-Q for future period detail
Period
Volume
(MBbls) $/Bbl(2)
2Q’17 249 $48.47
3Q’17 222 $48.43
4Q’17 203 $48.41
2017 Total 675
1Q’18 189 $49.40
2Q’18 35 $47.36
3Q’18 39 $47.36
4Q’18 42 $47.36
2018 Total 305
Period
Volume
(MBbls) $/Bbl(2)
2Q’17 182 $32.53
3Q’17 163 $32.42
4Q’17 149 $32.34
2017 Total 493
1Q’18 138 $35.41
2Q’18 26 $31.71
3Q’18 29 $31.71
4Q’18 32 $31.71
2018 Total 225
Period
Volume
(MBbls) $/Bbl(2)
2Q’17 634 $21.90
3Q’17 588 $21.91
4Q’17 550 $21.91
2017 Total 1,772
1Q’18 460 $23.35
2Q’18 440 $23.38
3Q’18 446 $23.55
4Q’18 442 $23.64
2018 Total 1,787
Period
Volume
(MBbls) $/Bbl(2)
2Q’17 157 $33.38
3Q’17 140 $33.28
4Q’17 128 $33.23
2017 Total 425
1Q’18 119 $35.44
2Q’18 21 $30.35
3Q’18 23 $30.35
4Q’18 25 $30.35
2018 Total 188
NGL Realizations
31
• Nearly 90% increase in realized price (before hedges) from 1Q16 to 1Q17
• SM NGL price realizations are predominately tied to Mont Belvieu, fee based contracts
• Differential reflects NGL barrel product mix and transportation and fractionation fees
1Q16 2Q16 3Q16 4Q16 1Q17
Mt. Belvieu ($/Bbl) $15.99 $20.04 $19.74 $24.11 $26.74
SM Realization
($/Bbl)$11.76 $16.12 $16.58 $20.02 $22.06
% Differential to
Mt. Belvieu74% 80% 84% 83% 82%
42%
28%
9%
9%
12%
SM Typical NGL Bbl(1)
Ethane PropaneIso Butane Normal ButanePentane
(1) Includes the effects of ethane rejection.
2017 Capital Program
32
Aggressive growth expected in the Midland Basin
Total Capital Budget ~$875MM
Other
86% 8%
Drilling and
Completion
86%
Facilities
6%
Other
8%Midland
Basin
80%
Operated Eagle
Ford
20%
• Average 7 rigs
• ~$750MM drilling and completion budget
• Planning more than 115 gross completions
(2)
(1) Approximately 10% of the drill and complete budget is related to non-operated assets, primarily in the Midland Basin.
(2) Other includes exploration and allocated overhead.
(1)
Setting Up for Expanded 2018 Program
33
Excellent vendor relationships and continued improvements in operating efficiencies
set the stage for expansion in 2018
• Use multiple contractors
• Eagle Ford: Rigs and frac crews contracted through year-end, sand volumes
and prices predominantly locked-in through year-end
• Midland Basin: Rigs and frac crews contracted through year-end with 7th rig;
vendors competing for market share
Significant
experience in
the basin –
strong vendor
relationships
Sufficient
takeaway
capacity
• Current oil pipeline takeaway 2.7 MMBbl/d vs. 2Q17(e) at 2.4 MMBbl/d
• Additional planned oil takeaway adds more than 650 MBbl/d by early 2018
Sufficient water
availability to
run program
• Sufficient water rights acquired to meet plan needs
• Saltwater disposal wells included in capital spend budget
• Sand supply companies adding significant capacity
Continued
performance
improvement
• RockStar drilling performance improved 25% in two months; one 7,500’ lateral
drilled in under 10 days
• Geosteering - placing laterals over 95% in zone, faster penetration rates
34
Excellent proximity to gathering/processing and takeaway with significant capacity
Midland Basin Infrastructure
Oil• 100% sold at wellhead
• 65% on pipeline (35% trucked)
• Currently working toward 100%
on pipeline
Gas• 100% sold at wellhead
• 100% third party gathered
NGLs• 100% sold at wellhead
• 100% third party gathered
• Current oil takeaway of 2.7 MMBbl/d vs. estimated 2Q17 oil production of 2.4 MMBbl/d
• Permian providers currently keeping up with growth – expected additional oil pipeline takeaway adds more than 650 MBbl/d by early 2018
• SM has sufficient water availability to meet plan needs
• SM anticipates adding SWDs (in SM capital spend budget)
Howard County Operators
35
SM Energy
Callon
Encana
Surge/Yantai Xinchao
Diamondback
Oxy
Energen
Breitburn
Sabalo
Sweetie Peck Operators
36
SM Energy
Apache
Chevron
Concho
Devon
Diamondback
Discovery
Endeavor
Exxon
Legacy
Oxy
Pioneer
Summit
Miscellaneous
Eagle Ford Operators
37
APC
APCAPC
APC
APC
CHK
CHK
NBL (ROSE)
SN
Lewis
SFY
SM EF North
SM EF South
SM EF East
Dimmit