BARCLAYS CEO ENERGY-POWER CONFERENCE · 2018-09-04 · BARCLAYS CEO ENERGY-POWER CONFERENCE...

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)


1,385 Boe/d

(87% oil)


909 Boe/d

(90% oil)


1,467 Boe/d

(85% oil)


1,070 Boe/d

(90% oil)

Farva B 4845WA

Farva A 4844WA


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 1761WB

Michael Scott 1762WB


1,198 Boe/d

(86% oil)

Kramer C 4843WA

Kramer D 4844WA

Kramer C 4862WB


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



Thumper 14-23 1AH

Sabalo – 10,105’


Midland 15-10 1WA

Hannathon – 7,726’


Broughton Wise 18-19 WA 1H


24hrIP = 875 BOEPD

Morgan Ranch 38-47 1WA


24hrIP = 713 BOEPD

HOWARD COUNTY WOLFCAMP B

35



International Unit 9H

Callon – 7,579’

24hrIP = 887 BOEPD

Maverick 0361WB

SM – 10,412’


Sundown 4566WB

SM – 10,336’


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’


HOWARD COUNTY LOWER SPRABERRY

36



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’


Papagiorgio 33-40 B1LS

SM – 10,370’


Allar LS



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

40

CONTACT INFORMATION

Jennifer Martin SamuelsVice President - Investor Relations [email protected]

BARCLAYS CEO ENERGY-POWER CONFERENCE · 2018-09-04 · BARCLAYS CEO ENERGY-POWER CONFERENCE...

Documents

Transcript of BARCLAYS CEO ENERGY-POWER CONFERENCE · 2018-09-04 · BARCLAYS CEO ENERGY-POWER CONFERENCE...