Upload
others
View
2
Download
0
Embed Size (px)
Citation preview
BARCLAYS CEO ENERGY-POWER
CONFERENCE
SEPTEMBER 4, 2018
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,” “assume,” “believe,” “pending,”
“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, guidance for production, total
capital spend, and other measures. General risk factors include 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 natural gas reserves; uncertainties inherent in projecting future drilling and
completion activities, costs or results, including from pilot tests; the uncertainty of negotiations to result in an agreement or a completed transaction;
uncertainties inherent in projecting the timing and ultimate outcome of litigation; 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, drilling carry, farm down 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; uncertainty regarding the ultimate impact of potentially dilutive securities; and other such matters discussed in the “Risk Factors”
section of SM Energy's 2017 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
(1) See Appendix for Cash Flow per Debt Adjusted Share definition
(2) Betty Jiang and William Featherston, Credit Suisse
OUR VISION
3
CREATING DIFFERENTIAL VALUE FOR OUR STAKEHOLDERS
~35%
PREMIER OPERATOR
TOP TIERASSETS
~35%C A G R 2 0 1 7 - 1 9
E x p e c t e d
CASH FLOW GROWTH
PER DEBT ADJUSTED SHARE(1)
“ CASH FLOW GROWTH PER
DEBT ADJUSTED SHARE IS
THE METRIC WITH THE
HIGHEST CORRELATION TO
INTRA SECTOR RELATIVE
PERFORMANCE”
– Credit Suisse 12/11/17(2)
SM ENERGY: A TRANSFORMED PORTFOLIO
4
FOCUSED ON TWO BASINS IN TEXAS
~35%
MIDLAND BASIN
▪ ~82,500 net acres
▪ 6 Rigs / 3 Frac Crews
EAGLE FORD
▪ ~165,000 net acres
▪ 1 Rig / 1 Frac Crew
5
Cash flow growth, up ~60% year over year(1)
• Big Midland production growth
• Rapid margin expansion; highest in 15 quarters
Operational execution: New wells outperforming • Record RockStar wells; 24 new RockStar wells average
1,330 Boe/d peak 30-day IP rates (87% oil)
• Increasing returns through efficiencies
Significant reduction/restructuring of long-term debt• Redeemed $345MM 6.5% Senior Notes
• Refinancing ~$480 MM in earlier maturities to 2027
$345 million ~$42/BoeDebt Reduction Permian Operating Margin(2)
RAPID IMPROVEMENTPRODUCTION UP, LEVERAGE DOWN
(1) 2Q18 / 2Q17
(2) 2Q18 Permian Basin regional production margin of $44.55 less corporate G&A per Boe.
MIDLAND BASIN
6
EXECUTING ON OUR PLAN
Midland Basin~82,500 net acres
RockStar
Sweetie
Peck
• 38 net completions in 2Q18
- 30 in RockStar area
• 6 rigs currently
• 3 frac fleets operating at high efficiency
• ~37 net completions expected in 3Q18; ~11 net completions expected in 4Q18
• Focusing on co-development of intervals
- 2019 kicks off with 25-well Merlin Maximus development expected to start 1Q19
MIDLAND BASIN PRODUCTION GROWTH TRAJECTORY
7
WELL PERFORMANCE + EFFICIENCY DRIVES PRODUCTION BEATS
Note: 2018 estimated Permian Basin production by quarter based on current plan.
• Expected Permian production growth up ~90% 2018/2017
• Production outperformance drives margin growth
4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18e 4Q18e
Pro
du
cti
on
(MB
oe)
Outperformance v. original plan
Outperformance v.
original plan
MIDLAND BASIN TOP WELL RESULTS
8
SM RANKS #1 IN REVENUE PER WELL(1)
(1) Baird Equity Research 8/13/18 – Joseph Allman
MIDLAND BASIN ROCKSTAR NEW WELL RESULTS
9
GREAT RESULTS - MULTIPLE INTERVALS - ACROSS ACREAGE
NEW WELLS AVERAGE 1,330 BOE/D, 87% OIL (10,180’ LATERAL LENGTH)
30 Day Avg Peak Rate:
1,735 Boe/d
(88% oil)
30 Day Avg Peak Rate:
1,385 Boe/d
(87% oil)
30 Day Avg Peak Rate:
909 Boe/d
(90% oil)
30 Day Avg Peak Rate:
1,467 Boe/d
(85% oil)
30 Day Avg Peak Rate:
1,070 Boe/d
(90% oil)
Farva B 4845WA
Farva A 4844WA
30 Day Avg Peak Rate:
1,070 Boe/d
(90% oil)
Kramer A 4841WA
Kramer B 4842WA
Kramer A 4861WB
Spackler 3326LS
Spackler 3346WA
Spackler 3372WB
Spackler 3364WB
O’Hagen 2047WA
O’Hagen 2048WA
Big Daddy A 1844WA
Big Daddy B 1845WA
Michael Scott 1741WA
Michael Scott 1742WA
Michael Scott 1743WA
Michael Scott 1761WB
Michael Scott 1762WB
30 Day Avg Peak Rate:
1,198 Boe/d
(86% oil)
Kramer C 4843WA
Kramer D 4844WA
Kramer C 4862WB
30 Day Avg Peak Rate:
1,266 Boe/d
(85% oil)
Costanza B 4846WA
Costanza A 4863WB
Costanza C 4864WB
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 PEER 1MMBOE
MIDLAND BASIN ROCKSTAR NEW WELL RESULTS
10
NEW WELLS AT TIGHTER AVERAGE SPACING
Note: Monthly data normalized to days on production; as of July 23, 2018
(1) Previously Reported Well Average includes all (55) previously reported SM operated wells on production since 11/3/2016.
(2) New Well Average includes 24 new wells that have not been previously reported.
(1) (2)
0.7
0.8
0.9
1.0
1.1
Jan Feb Mar Apr May Jun Jul
Sa
nd
Co
st
Ind
ex
Ind
exe
d to
No
rth
ern
Wh
ite
–Ja
n 1
8
11
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%
3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18
Pe
rce
nt
Imp
rove
me
nt
(1) Excludes last mile logistics
MIDLAND BASIN DRIVING CAPITAL EFFICIENCY
12
LOCAL SAND ARRANGEMENT WITH US SILICA & SANDBOX LOGISTICS
Lamesa (3Q18)
Crane (1Q18)
~55 miles(1)
~48 miles(1)
New sand mines
close to SM
operations
Substantial
capital savings
per well
(1) Road miles
MIDLAND BASIN WATER MANAGEMENT INFRASTRUCTURE
13
BACKBONE OF INFRASTRUCTURE IN PLACE
Accelerates
development
Expected cost
savings (LOE + Capital)
System
control
Currently 95%+
Midland water on pipe
TAKEAWAY COMMITMENTS + PRICING PROTECTIONPERMIAN OIL TAKEAWAY AND PRICING
14
Midland – Cushing Oil Basis Swaps
• 2H18: 6,345 MBbls of Permian oil production covered by basis
hedges at an average price differential of $1.07
• 2019: 11,216 MBbls of Permian oil production covered by basis
hedges at an average price differential of $3.36
Takeaway commitments
• Firm sales agreements in place with multiple purchasers that
cover current and projected oil production over the next year
15
Eagle Ford ~165,000 net acres
EAGLE FORDENHANCING INVENTORY VALUE
• Assessing new intervals
• Up-spacing / increasing lateral
length
• Optimizing completions
• Currently running 1 rig and 1
frac fleet
• Expect to complete 4 net wells
in 3Q18; 7 net completions
expected in 4Q18
BALANCE SHEET OFFERS FINANCIAL FLEXIBILITY
16
LIQUIDITY OF $1.3B(1)
$500$500$500$500$476.8
$172.5 $0
$250
$500
$750
$1,000
$1,250
$1,500
2027202620252024202320222021202020192018
Debt Maturities(2)
(in millions)
$0 drawn
Borrowing Base: $1.27B
Commitments: $1.0B
Coupon 1.500% 6.125% 5.000% 5.625% 6.750% 6.625%
Yield to worst(2) - 4.73% 5.59% 5.76% 6.07% 6.10%
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) June 30, 2018 liquidity of $1.6 billion adjusted for 2021 Senior Notes redemption
(2) Debt maturities as of August 17, 2018; YTW as of August 30, 2018
(3) Approximately $10.5MM principal amount of the Company’s 6.5% Senior Notes due 2023 remains outstanding as of 8/17/18; as publicly
announced on 8/20/18, the Company expects to redeem the remaining outstanding principal amount of these notes following the expiration of the
tender offer.
• $345 million in 6.5% senior notes due 2021 redeemed subsequent to quarter-end
• Extended ~$480MM in earlier maturities to 2027
• Net debt:TTM Adjusted EBITDAX 3.1 times at 6/30/18; expected to be below
3.0 times at year-end 2018
(3)
WELL HEDGED
17
PERCENTAGE OF EXPECTED PRODUCTION HEDGED
Production Hedged(1)
80%
70%
Midland-Cushing Basis Swaps
• ~80% of expected 2H18 production volumes hedged;
~80% of oil volumes, ~70% of gas volumes (NGLs
hedged by product)
• ~45% of expected 2019 production volumes hedged;
~50% oil volumes, ~25% gas volumes (NGLs hedged
by product)
• ~70% of expected 2H18 Permian oil production
covered by basis hedges at just over $1/Bbl
• >50% of expected 2019 Permian oil production
covered by basis hedges
Note: Hedging data as of August 30, 2018; all percentages calculated using mid-point of guidance.
(1) Percentage includes oil swaps and collars, natural gas swaps and collars, and NGL swaps; does not include basis swaps.
18
25-well Merlin-Maximus development; rigs from left to right: Ensign 772, Ensign 769, Trinidad 57, and Ensign 767
SM ENERGYWHY INVEST IN SM?
• Opportunity to participate in high rate of change story at compelling value.
• Assets: SM wells ranked best in Midland Basin
• Execution: Exceptional track record
• Rapidly de-levering with ample liquidity
• Returns focused: executive compensation tied to returns
Appendix
19
Operational Detail
20
21
Benchmark Pricing
NYMEX WTI Oil ($/Bbl) $67.88
NYMEX LLS Oil ($/Bbl) $71.20
NYMEX Henry Hub Gas ($/MMBtu) $2.80
Hart Composite NGL ($/Bbl) $33.10
Production Volumes Eagle Ford(1) Permian Rocky Mountain Total
Oil (MBbls) 332 3,731 298 4,361
Gas (MMcf) 18,807 6,201 316 25,323
NGL (MBbls) 1,894 5 1 1,900
MBoe 5,360 4,770 352 10,482
Revenue (in thousands)
Oil $19,346 $227,636 $19,168 $266,150
Gas 52,235 31,734 95 84,064
NGL 52,248 129 (33) 52,344
Total $123,829 $259,499 $19,230 $402,558
Expenses (in thousands)
LOE $10,783 $32,889 $5,160 $48,832
Ad Valorem 3,190 1,133 - 4,323
Transportation 46,204 111 544 46,860
Production Taxes 2,652 12,884 1,848 17,384
Per Unit Metrics:
Realized Oil per Bbl $58.20 $61.01 $64.29 $61.02
% of Benchmark - WTI 86% 90% 95% 90%
Realized Gas per Mcf $2.78 $5.12 nm $3.32
% of Benchmark – NYMEX HH 99% 183% nm 119%
Realized NGL per Bbl $27.59 nm nm $27.55
% of Benchmark – HART 83% nm nm 83%
Realized per Boe $23.10 $54.41 $54.61 $38.40
LOE per Boe $2.01 $6.90 $14.65 $4.66
Transportation per Boe $8.62 $0.02 $1.55 $4.47
Ad Val per Boe $0.60 $0.24 - $0.41
Production Tax - per BOE/% of Pre-Hedge
Revenue$0.49/2.1% $2.70/5.0% $5.25/9.6% $1.66/4.3%
Production Margin per Boe $11.38 $44.55 $33.16 $27.20
Note: Totals may not sum due to rounding and other classifications
(1) Includes nominal amounts of other production and expenses from the region.
2Q18 REALIZATIONS BY REGION
22
NGL REALIZATIONS
• 40% increase in realized price (before hedges) from 2Q17 to 2Q18
• SM NGL price realizations are predominantly tied to Mont Belvieu, fee based contracts
• Differential reflects NGL barrel product mix, and transportation and fractionation fees
42%
27%
9%
9%
13%
SM Typical NGL Bbl(1)
Ethane Propane
Iso Butane Normal Butane
Natural Gasoline
2Q17 3Q17 4Q17 1Q18 2Q18
Mt. Belvieu ($/Bbl) $24.11 $27.55 $32.12 $30.87 $33.10
SM Realization
($/Bbl)$19.71 $22.40 $26.01 $25.53 $27.55
% Differential to
Mt. Belvieu82% 81% 81% 83% 83%
(1) Includes the effects of ethane rejection; if the Company elects to recover ethane, the ethane percentage
is over 50%. To date, the Company has elected to process ethane in May, July, and August during 2018.
2018 ACTIVITY BY REGION
23
WELLS DRILLED, FLOWING COMPLETIONS, AND DUC COUNT
Wells Drilled Flowing Completions DUC Count(3)
2nd Quarter 2018 2018 YTD 2nd Quarter 2018 2018 YTD As of June 30, 2018
Region Gross Net Gross Net Gross Net Gross Net Gross Net
Permian
Sweetie Peck 4 4 7 7 8 8 12 10 4 4
RockStar 25 24 57 54 33 30 51 45 46 44
Permian total 29 28 64 61 41 38 63 55 50 48
Eagle Ford(1) 10 6 21 14 16 9 21 14 33 30
Subtotal Operated Wells 39 34 85 75 57 47 84 69 83 78
Non-operated Wells(2) n/a - n/a - n/a 1 n/a 1 n/a -
Total n/a 34 n/a 75 n/a 48 n/a 70 n/a 78
As of June 30, 2018
(1) During the first six months of 2018, there were 8 gross JV wells drilled, 8 JV wells completed, and 4 gross JV DUCs
(2) Non-operated activity relates to wells located in the Permian Basin
(3) 18 gross / 15 net DUCs related to Rockies were removed due to the closed asset sale
LEASEHOLD SUMMARY
24
~760 NET ACRE BOLT-ON AT ROCKSTAR IN 2Q18
RegionNet Acres(1)
6/30/2018
Midland Basin
RockStar 65,580
Sweetie Peck(2) 16,880
Midland Basin Total 82,460
Eagle Ford 164,680
Rocky Mountain Other(3) 186,845
Other Areas/Exploration 24,915
Total 458,900
(1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of June 30, 2018. Miscellaneous
Powder River Basin acreage sold subsequent to 6/30/18 removed from table.
(2) Sweetie Peck acreage includes 2,450 net acres of drill-to-earn acreage.
(3) Rocky Mountain Other includes non-core Williston Basin, and other non-core acreage located in North Dakota, Montana, Wyoming, and Utah.
Financial Detail
25
2ND QUARTER 2018 AND 1H18 PERFORMANCE
26
SOLID EXECUTION
Production & Pricing 2Q18 1H18
Total Production (MMBoe/MBoe/d) 10.5/115.2 20.6/113.9
Oil Percentage 42% 42%
Pre-Hedge Realized Price ($/Boe) $38.40 $38.09
Post-Hedge Realized Price ($/Boe) $34.91 $35.12
Costs $/Boe $/Boe
LOE $4.66 $4.80
Ad Valorem $0.41 $0.54
Transportation $4.47 $4.55
Production Taxes $1.66 $1.67
Production Expenses $11.20 $11.56
Cash Production Margin (pre-hedge) $27.20 $26.53
G&A – Cash $2.37 $2.34
G&A – Non Cash $0.39 $0.40
Operating Margin (pre-hedge) $24.44 $23.79
DD&A $14.48 $13.69
EPS (Diluted) $0.15 $2.95
Adjusted EPS $0.15 $0.21
(1) See Appendix for reconciliation of non-GAAP measures
$225.0 MMAdjusted EBITDAX(1)
2Q18
$189.9 MMDiscretionary
Cash Flow(1)
2Q18
60% increase(year over year)
27
2018 PLAN GUIDANCE(1)
Capital & Production FY 2018
Total Capital Spend ($MM)(2) (before acquisitions) ~$1,310
Total Production (MMBoe) 43.5 – 45.0
Total Production (MBoe/d) 119 – 123
Oil % ~42%
Costs
LOE ($/Boe) ~$5.00
Ad Valorem taxes ($/Boe) ~$0.50
Transportation ($/Boe) ~$4.50
Production taxes (% of pre-hedge revenue) 4.0 – 4.5%
G&A ($MM) – includes ~$20MM non-cash compensation
$115 – 125
Capitalized Overhead/Exploration ($MM)– before dry hole expense, all of which is
included in capital expenditure guidance
$70 – 75
DD&A ($/Boe) $13.00 – $15.00
(1) As of August 1, 2018
(2) Total Capital Spend is a non-GAAP financial measure; reconciliation of this measure is provided in the Appendix. The Company is unable to present a
quantitative reconciliation of this forward-looking, non-GAAP financial measure without unreasonable effort because acquisition costs are inherently
unpredictable.
• 3Q18 production guidance 11.2-11.7 MMBoe / 122-127 MBoe/d (~42% oil)
• 2H18 total capital spend expected to be ~$514MM and weighted toward 3Q18;
expect to complete ~41 net wells in 3Q18 and ~18 net wells in 4Q18
0
20
40
60
80
100
120
140
1Q18 2Q18 3Q18e 4Q18e
Pro
du
cti
on
(B
oe
/d)
2018 Production by Quarter
Retained Assets Sold
OIL AND GAS DERIVATIVE POSITIONS
28
BY QUARTER THROUGH 2019
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)
3Q’18 1,769 $49.77 1,948 $58.61 $50.00 3,018 ($1.06)
4Q’18 1,894 $49.87 2,222 $58.44 $50.00 3,327 ($1.08)
1Q’19 442 $50.70 2,503 $64.32 $51.66 2,017 ($3.54)
2Q’19 439 $50.70 2,801 $64.61 $52.18 2,571 ($4.49)
3Q’19 524 $50.70 2,364 $62.67 $49.07 3,291 ($2.86)
4Q’19 535 $50.70 2,386 $62.65 $49.08 3,338 ($2.87)
Note: Includes all commodity derivative contracts for settlement at any time during the third quarter of 2018 and later periods through 2019, entered into as of 8/30/18.
(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)
3Q’18 20,738 $2.90 - - -
4Q’18 20,994 $2.92 - - -
1Q’19 16,979 $2.92 - - -
2Q’19 - - 4,358 $2.83 $2.50
3Q’19 - - 5,066 $2.83 $2.50
4Q’19 - - 4,818 $2.83 $2.50
NGL DERIVATIVE SWAP POSITIONS
29
OPIS MT. BELVIEU
Ethane Purity
Period
Volume
(MBbls) $/Bbl(2)
3Q’18 1,033 $10.99
4Q’18 1,146 $11.18
2018 Total 2,179
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)
3Q’18 610 $24.27
4Q’18 671 $24.39
2018 Total 1,281
1Q’19 440 $26.13
2Q’19 462 $29.45
3Q’19 544 $29.79
4Q’19 533 $29.77
2019 Total 1,979
Iso Butane
Period
Volume
(MBbls) $/Bbl(2)
3Q’18 70 $35.07
4Q’18 76 $35.07
2018 Total 146
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)
3Q’18 202 $51.13
4Q’18 208 $50.99
2018 Total 410
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)
3Q’18 93 $35.70
4Q’18 102 $35.70
2018 Total 195
1Q’19 37 $35.64
2Q’19 38 $35.64
3Q’19 39 $35.64
4Q’19 39 $35.64
2019 Total 153
(1) Includes all commodity derivative contracts for settlement at any time during the third quarter of 2018 and later periods, entered into as of August 30, 2018.
(2) Weighted-Average Contract Price
30
ADJUSTED EBITDAX RECONCILIATIONReconciliation of net income (GAAP) and net cash
provided by operating activities (GAAP) to adjusted
EBITDAX (non-GAAP): (in thousands)
Three Months Ended
June 30, 2018
Six Months Ended
June 30, 2018Net income (GAAP) $17,197 $334,598
Interest expense 41,654 84,739
Interest income (2,414) (3,263)
Income tax expense (901) 98,090
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 151,765 282,238
Exploration(1) 12,867 25,278
Abandonment and impairment of unproved properties 11,935 17,560
Stock-based compensation expense 5,264 10,676
Net derivative loss 63,749 71,278
Derivative settlement loss (36,665) (61,193)
Net gain on divestiture activity (39,501) (424,870)
Other 2 9
Adjusted EBITDAX (Non-GAAP) $224,952 $435,140
Interest expense (41,654) (84,739)
Interest income 2,414 3,263
Income tax expense 901 (98,090)
Exploration(1) (12,867) (25,278)
Amortization of debt discount and deferred financing costs 3,884 7,750
Deferred income taxes (861) 97,505
Other, net 223 (2,311)
Net change in working capital (5,609) (21,722)
Net cash provided by operating activities (GAAP) $171,383 $311,518
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 one-time 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 senior secured debt to adjusted EBITDAX and a minimum permitted ratio of adjusted EBITDAX to interest, 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.
(1) 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.
31
ADJUSTED NET INCOME RECONCILIATION
Reconciliation of net income (GAAP) to
adjusted net income (non-GAAP):
(in thousands, except per share data)
Three Months Ended
June 30, 2018
Six Months Ended
June 30, 2018Net income (GAAP) $17,197 $334,598
Net derivative loss 63,749 71,278
Derivative settlement loss (36,665) (61,193)
Net gain on divestiture activity (39,501) (424,870)
Abandonment and impairment of unproved properties 11,935 17,560
Other, net 2 809
Tax effect of adjustments(1) 104 86,022
Adjusted net income (Non-GAAP) $16,821 $24,204
Diluted net income per common share (GAAP) $0.15 $2.95
Net derivative loss 0.56 0.63
Derivative settlement loss (0.32) (0.54)
Net gain on divestiture activity (0.35) (3.75)
Abandonment and impairment of unproved properties 0.11 0.16
Other, net - 0.01
Tax effect of adjustments(1) - 0.74
Adjusted net income per diluted common share (Non-GAAP) $0.15 $0.21
Diluted weighted-average common shares outstanding (GAAP): 113,630 113,267
Adjusted net income 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 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.
(1) The tax effect of adjustments is calculated using a tax rate of 21.7%, for the three-month and six-months periods ended June 30, 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
DISCRETIONARY CASH FLOW
32
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
June 30, 2018
Six Months Ended
June 30, 2018
Net cash provided by operating activities (GAAP): $171.4 $311.5
Net change in working capital 5.6 21.7
Exploration(2)(3) 12.9 25.3
Discretionary cash flow (Non-GAAP): $189.9 $358.5
(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.
Maps
33
HOWARD COUNTY WOLFCAMP A
34
EVOLUTION OF SM SWEET SPOT MAPPING
January 2017 February 2018
Hyden 47-38 WA 1H
Grenadier – 9,639’
24hrIP = 848 BOEPD
Higginbotham Unit B 30-19 1AH
Tall City – 6,397’
24hrIP = 398 BOEPD
Cassidy 26-23 1H
Tall City – 7,314’
24hrIP = 403 BOEPD
Viper 14-9 1WA
SM – 10,422’
24hrIP = 1,316 BOEPD
Oldham Trust 40-25 WA 1H
Grenadier – 10,426’
24hrIP = 1,274 BOEPD
Thumper 14-23 1AH
Sabalo – 10,105’
24hrIP = 1,357 BOEPD
Midland 15-10 1WA
Hannathon – 7,726’
24hrIP = 1,259 BOEPD
Broughton Wise 18-19 WA 1H
Grenadier – 7,012’
24hrIP = 875 BOEPD
Morgan Ranch 38-47 1WA
Hannathon – 7,727’
24hrIP = 713 BOEPD
HOWARD COUNTY WOLFCAMP B
35
EVOLUTION OF SM SWEET SPOT MAPPING
January 2017 February 2018
International Unit 9H
Callon – 7,579’
24hrIP = 887 BOEPD
Maverick 0361WB
SM – 10,412’
24hrIP = 1,683 BOEPD
Sundown 4566WB
SM – 10,336’
24hrIP = 1,435 BOEPD
Prichard J 10BH
Legacy – 7,644’
24hrIP = 602 BOEPD
Prichard J 9BH
Legacy – 7,641’
24hrIP = 655 BOEPD
Fletch C 1368WB
SM – 10,287’
24hrIP = 1,700 BOEPDTubb 1WA
Crownquest – 9,873’
24hrIP = 1,178 BOEPD
HOWARD COUNTY LOWER SPRABERRY
36
EVOLUTION OF SM SWEET SPOT MAPPING
January 2017 February 2018
Moby Dick 31-30 8SH
Surge – 7,362’
24hrIP = 319 BOEPD
Sundown 4524 LS
SM – 10,352’
24hrIP = 959 BOEPD
Mr. Phillips 11-2 1SH
Sabalo – 10,047’
24hrIP = 1,032 BOEPD
Papagiorgio 33-40 B1LS
SM – 10,370’
24hrIP = 1,006 BOEPD
Allar LS
Hannathon – 7,580’
24hrIP = 1,135 BOEPD
37
ROCKSTAR OPERATORS
SM Energy
Callon
Encana
Surge/Yantai Xinchao
Diamondback
Oxy
Energen
Endeavor
Sabalo
Grenadier
Note: Peer acreage obtained from 1Derrick
Birch Permian
38
SWEETIE PECK OPERATORS
SM Energy
Apache
Chevron
Concho
Devon
Diamondback
Discovery
Endeavor
Exxon
Legacy
Oxy
Pioneer
Summit
Note: Peer acreage obtained from 1Derrick
39
EAGLE FORD OPERATORS
Fasken
AreaNorth
AreaEast
AreaSouth
DimmitWebb
Dim
mit
Maverick