1q18 earnings outstanding execution · 1q18 earnings outstanding ... uncertainty regarding the...
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1Q18 EARNINGSOUTSTANDING EXECUTION
MAY 3, 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, full year 2018 guidance, second
quarter of 2018 guidance, expectations concerning the planned closing of previously announced divestitures, expectations about future cost inflation, and
the expected benefits from joint venture arrangements. 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
2017-2019 DRIVING DIFFERENTIAL VALUE
3
OFF TO A GREAT START IN 2018
~35%
PREMIER OPERATOR
TOP TIERASSETS
~35%C A G R 2 0 1 7 - 1 9
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)
4
FIRST QUARTER 2018 HIGHLIGHTS
Cash flow growth, up 30% sequentially
• Rapid margin expansion, highest in 14 quarters
• Big Midland production growth
Operational execution: New wells outperforming expectations
• 19 new RockStar wells average 1,440 Boe/d peak
30-day IP rates (88% oil)
Significant reduction in net debt
• Non-core asset sales year-to-date reduce net debt and
core up portfolio
$792 million $1.6 billionNon-core asset sales(1) Liquidity(2)
(1) Includes closed sale of Powder River Basin assets, and expected proceeds from pending sales of non-core assets in North Dakota and Texas
(2) As of March 31, 2018; borrowing base and commitment amount as of May 2, 2018
1ST QUARTER 2018
5
SOLID EXECUTION
Production & Pricing 1Q18
Total Production (MMBoe/MBoe/d) 10.1/112.7
Oil Percentage 42%
Pre-Hedge Realized Price ($/Boe) $37.76
Post-Hedge Realized Price ($/Boe) $35.34
Costs $/Boe
LOE $4.95
Ad Valorem $0.67
Transportation $4.63
Production Taxes $1.68
Production Expenses $11.93
Cash Production Margin (pre-hedge) $25.83
G&A – Cash $2.33
G&A – Non Cash $0.40
Operating Margin (pre-hedge) $23.10
DD&A $12.87
$210.2 MMAdjusted EBITDAX(1)
(1) See Appendix for reconciliation of non-GAAP measures
$168.7 MMDiscretionary
Cash Flow (1)
30% increase(over 4Q17)
BALANCE SHEET OFFERS FINANCIAL FLEXIBILITY
6
LIQUIDITY OF $1.6B, INCLUDING $643MM CASH ON HAND(1)
$500$500$500$395$562
$345
$172.5
$0
$250
$500
$750
$1,000
$1,250
$1,500
202620252024202320222021202020192018
Debt Maturities(1)
(in millions)
$0 drawn
Borrowing Base: $1.4B
Commitments: $1.0B
Coupon 1.500%
6.500%6.125% 6.500% 5.000% 5.625% 6.750%
Yield to worst(2) 5.11% 5.67% 6.23% 5.99% 6.22% 6.38%
Initial call date 11/2016 11/2018 7/2017 7/2018 6/2020 9/2021
Initial call price 103.25% 103.06% 103.25% 102.50% 102.81% 103.38%
(1) Cash on hand as of March 31, 2018; borrowing base and commitment amount as of May 2, 2018.
(2) As of April 30, 2018
• Rapidly reducing net debt with expected $792MM non-core asset sales year-to-date
• Net debt:TTM Adjusted EBITDAX 3.3 times at 3/31/18; below 3.0 times projected year-end
• Borrowing base increased to $1.4B; commitments increased to $1.0B
• No bond maturities until 2021
• Senior Secured Debt:TTM Adjusted EBITDAX at 0.0 times; max ratio allowed 2.75 times
• TTM Adjusted EBITDAX:Interest at ~4.1 times; minimum ratio required 2.0 times
WELL HEDGED
7
PERCENTAGE OF EXPECTED PRODUCTION HEDGED
Production Hedged(1)
80%
70%
Midland-Cushing Basis Swaps
• ~80% of expected 2Q18 – 4Q18 production volumes
hedged; ~85% of oil volumes, ~65% of gas volumes
(NGLs hedged by product)
• ~75% of expected 2Q18 production volumes hedged;
~75% of oil volumes, ~65% of gas volumes (NGLs
hedged by product)
• ~40% of expected 2019 production volumes hedged;
~50% oil volumes, ~25% gas volumes (NGLs hedged
by product)
• ~70% of expected 2Q18 – 4Q18 Permian oil
production covered by basis hedges at just over $1/Bbl
• ~1/3 of expected 2019 Permian oil production covered
by basis hedges
Note: Hedging data as of May 2, 2018; all percentages calculated using mid-point of guidance.
(1) Percentage includes oil swaps and collars, natural gas swaps and collars , and NGL swaps; does not include basis swaps.
8
2018 PLAN GUIDANCE(1)
Capital & Production FY 2018
Total Capital Spend ($MM)(2) (before acquisitions) ~$1,270
Total Production (MMBoe) 40.9 – 44.9
Total Production (MBoe/d) 112 – 123
Oil % ~40%
Costs
LOE ($/Boe) ~$5.00
Ad Valorem taxes ($/Boe) $0.55 – $0.65
Transportation ($/Boe) ~$4.50
Production taxes (% of pre-hedge revenue) 4.0 – 4.5%
G&A ($MM) – includes ~$20MM non-cash compensation
$125 – 135
Capitalized Overhead/Exploration ($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 May 2, 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.
• 2Q18 production guidance 9.7-10.1 MMBoe / 106-111 MBoe/d (~40% oil)
• 2Q18 total capital spend expected to be similar to 1Q18 at $367MM; expect to complete ~45 net wells
• Ad Valorem and Production taxes are expected to be at the higher end of the provided range based on current oil prices
0
25
50
75
100
125
150
1Q18 2Q18e 3Q18e 4Q18e
Pro
du
ctio
n (
Bo
e/d
)
2018 Production Guidance by Quarter
Retained Assets Pending Sale/Sold
ROCKSTAR NEW WELL RESULTS
9
GREAT RESULTS IN MULTIPLE INTERVALS ACROSS ACREAGE POSITION
NEW WELLS AVERAGE 1,440 BOE/D, 88% OIL (10,200’ LATERAL LENGTH)
Wiley Bob A 2351WA
Wiley Bob 2352WA(1)
Guitar North 2850WA
Guitar North 2851WA
Guitar North 2852WA
Guitar North 2867WB
Guitar North 2868WB
Berlinda Ann 2341WA
Berlinda Ann 2342WA
Berlinda Ann 2361WB
Whitaker 22-27 Unit 2251WA
Whitaker 22-27 Unit 2252WA
Lumbergh 2547WA
Lumbergh 2548WA
Lumbergh 2565WB
30 Day Avg Peak Rate:
1,607 Boe/d
(87% oil)
30 Day Avg Peak Rate:
1,623 Boe/d
(85% oil)
30 Day Avg Peak Rate:
1,305 Boe/d
(90% oil)
Lumbergh 2527LS
Lumbergh 2528LS
30 Day Avg Peak Rate:
1,485 Boe/d
(87% oil)
30 Day Avg Peak Rate:
941 Boe/d
(90% oil)(1) 7,708’ lateral length
Fezzik A 2443WA
Fezzik A 2444WA
30 Day Avg Peak Rate:
1,536 Boe/d
(89% oil)
ROCKSTAR NEW WELL RESULTS
10
NEW WELLS CONTINUE OUTPERFORMANCE TREND
Note: Monthly data normalized to days on production; as of April 26, 2018
(1) Previously Reported Well Average includes all (36) previously reported SM operated wells on production since 11/3/2017.
(2) New Well Average includes 19 new wells that have not been previously reported.
0
50,000
100,000
150,000
200,000
250,000
300,000
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(1) (2)
MIDLAND BASIN
11
EXECUTING ON OUR PLAN
Midland Basin~82,500 net acres(1)
RockStar
Sweetie
Peck
(1) Excludes acreage related to announced Halff East divestiture that is expected to close during 2Q18.
• 17 net completions in 1Q18
- 15 in RockStar area
• 9 rigs currently; expect to reduce
to 8 in 2Q18
• 5 frac fleets operating at high
efficiency
• ~36 net completions expected in
2Q18
• Focusing on co-development of
intervals
12
Eagle Ford ~165,000 net acres
EAGLE FORDENHANCING VALUE OF INVENTORY
• Up-spacing to improve returns
• Assessing new intervals
• Optimizing completions
• Running 2 rigs and 1 frac fleet
• Expect to complete 9 net wells
in 2Q18
13
SM ENERGY PREMIER OPERATOR OF TOP TIER ASSETS
✓Excellent execution in 1Q18
✓On track / ahead of 2018 plan
✓High returns leading to rapid
debt-adjusted per share cash
flow growth
SUMMARY
Appendix
14
Operational Detail
15
16
Benchmark Pricing
NYMEX WTI Oil ($/Bbl) $62.87
NYMEX Henry Hub Gas ($/MMBtu) $3.00
Hart Composite NGL ($/Bbl) $30.87
Production Volumes Eagle Ford(1) Permian Rocky Mountain Total
Oil (MBbls) 354 3,315 592 4,262
Gas (MMcf) 18,731 5,631 861 25,222
NGL (MBbls) 1,641 5 27 1,673
MBoe 5,117 4,259 763 10,139
Revenue (in thousands)
Oil $19,583 $205,794 $35,683 $261,060
Gas 52,733 24,876 1,500 79,109
NGL 41,770 124 823 42,717
Total $114,086 $230,794 $38,006 $382,886
Expenses (in thousands)
LOE $11,321 $28,292 $10,572 $50,174
Ad Valorem 2,361 4,366 50 6,777
Transportation 45,307 197 1,396 46,900
Production Taxes 1,921 11,359 3,748 17,028
Per Unit Metrics:
Realized Oil per Bbl $55.27 $62.07 $60.27 $61.25
% of Benchmark - WTI 88% 99% 96% 97%
Realized Gas per Mcf $2.82 $4.42 $1.74 $3.14
% of Benchmark – NYMEX HH 94% 147% 58% 105%
Realized NGL per Bbl $25.45 $24.29 $30.36 $25.53
% of Benchmark – HART 82% 79% 98% 83%
Realized per Boe $22.29 $54.19 $49.84 $37.76
LOE per Boe $2.21 $6.64 $13.86 $4.95
Transportation per Boe $8.85 $0.05 $1.83 $4.63
Ad Val per Boe $0.46 $1.03 $0.07 $0.67
Production Tax - per BOE/% of Pre-Hedge
Revenue$0.38/1.7% $2.67/4.9% $4.92/9.9% $1.68/4.4%
Production Margin per Boe $10.39 $43.80 $29.16 $25.83
Note: Totals may not sum due to rounding and other classifications
(1) Includes nominal amounts of other production and expenses from the region.
1Q18 REALIZATIONS BY REGION
17
2018 PLANNED RIG ACTIVITY AND COMPLETIONS BY MONTH
0
20
40
60
80
100
120
0
2
4
6
8
10
12
14
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
To
tal N
et
DU
Cs
(1)
Op
era
ted
Rig
s
Midland Basin Eagle Ford Total Net DUCs
(1) Total Net DUCs counts remove DUCs associated with assets sold / pending sale.
18
NGL REALIZATIONS
• 16% increase in realized price (before hedges) from 1Q17 to 1Q18
• SM NGL price realizations are predominantly tied to Mont Belvieu, fee based contracts
• Differential reflects NGL barrel product mix, and transportation and fractionation fees
42%
27%
9%
9%
13%
SM Typical NGL Bbl(1)
Ethane Propane
Iso Butane Normal Butane
Natural Gasoline
1Q17 2Q17 3Q17 4Q17 1Q18
Mt. Belvieu ($/Bbl) $26.74 $24.11 $27.55 $32.12 $30.87
SM Realization
($/Bbl)$22.06 $19.71 $22.40 $26.01 $25.53
% Differential to
Mt. Belvieu82% 82% 81% 81% 83%
(1) Includes the effects of ethane rejection
2018 ACTIVITY BY REGION
19
WELLS DRILLED, FLOWING COMPLETIONS, AND DUC COUNT
Wells Drilled Flowing Completions DUC Count
1st Quarter 2018 1st Quarter 2018 1st Quarter 2018
Region Gross Net Gross Net Gross Net
Permian
Sweetie Peck 3 3 4 2 8 8
RockStar 32 30 18 15 54 50
Permian total 35 33 22 17 62 58
Eagle Ford(1) 11 8 5 5 39 33
Rocky Mountain (Divide) - - - - 18 15
Subtotal Operated Wells 46 41 27 22 119 106
Non-operated Wells(3) n/a - n/a - n/a 1
Total n/a 41 n/a 22 n/a 107
(1) As of March 31, 2018, there were 4 gross JV wells drilled, 0 JV wells completed, and 8 gross JV DUC’s
(2) Expected to be sold during 2Q18
(3) Non-operated activity relates to wells located in the Permian Basin
(2)
LEASEHOLD SUMMARY
20
PRO-FORMA FOR PENDING TRANSACTIONS
Region
Net
Acres(1)
3/31/18
Pending Sales /
Additions
Pro-forma
Net Acres
Midland Basin
RockStar 64,855 760 65,615
Sweetie Peck(2) 16,900 - 16,900
Halff East 5,420 (5,420) -
Midland Basin Total 87,175 (4,660) 82,515
Eagle Ford 164,680 - 164,680
Rocky Mountain
Divide 119,235 (119,235) -
Rocky Mountain Other(3) 186,845 - 186,845
Other Areas/Exploration 24,915 - 24,915
Total 582,850 (123,895) 458,955
(1) Includes developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held as of March 31, 2018.
(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
21
OIL AND GAS DERIVATIVE POSITIONS
22
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)
2Q’18 1,534 $49.57 1,459 $59.03 $50.00 2,392 ($1.03)
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 1,865 $61.08 $49.38 1,471 ($1.27)
2Q’19 439 $50.70 1,990 $61.44 $49.66 1,546 ($1.32)
3Q’19 524 $50.70 2,079 $61.51 $48.26 1,641 ($1.33)
4Q’19 535 $50.70 2,092 $61.46 $48.25 1,660 ($1.33)
Note: Includes all commodity derivative contracts for settlement at any time during the second quarter of 2018 and later periods through 2019, entered into as of 5/2/18.
(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)
2Q’18 15,712 $2.85 - - -
3Q’18 17,147 $2.88 - - -
4Q’18 18,646 $2.91 - - -
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
23
OPIS MT. BELVIEU
Ethane Purity
Period
Volume
(MBbls) $/Bbl(2)
2Q’18 915 $10.87
3Q’18 1,033 $10.99
4Q’18 1,146 $11.18
2018 Total 3,094
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)
2Q’18 554 $24.94
3Q’18 610 $24.27
4Q’18 671 $24.39
2018 Total 1,835
1Q’19 440 $26.13
2Q’19 348 $28.53
3Q’19 360 $28.53
4Q’19 355 $28.53
2019 Total 1,503
Iso Butane
Period
Volume
(MBbls) $/Bbl(2)
2Q’18 66 $35.07
3Q’18 70 $35.07
4Q’18 76 $35.07
2018 Total 212
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)
2Q’18 175 $50.99
3Q’18 202 $51.13
4Q’18 208 $50.99
2018 Total 585
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)
2Q’18 84 $35.69
3Q’18 93 $35.70
4Q’18 102 $35.70
2018 Total 279
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 second quarter of 2018 and later periods, entered into as of May 2, 2018.
(2) Weighted-Average Contract Price
TOTAL CAPITAL SPEND
24
RECONCILIATION TO COSTS INCURRED (GAAP)
Reconciliation of costs incurred in oil and gas
activities (GAAP) to total capital spend
(Non-GAAP)(1) (in millions)
Three Months Ended
March 31, 2018
Costs incurred in oil and gas activities (GAAP): $372.2
Asset retirement obligation (0.9)
Capitalized interest (4.5)
Total capital spend (Non-GAAP): $366.7
(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.
Note: Amounts may not calculate due to rounding
25
ADJUSTED EBITDAX RECONCILIATION
Reconciliation of net income (GAAP) and net cash provided by operating
activities (GAAP) to adjusted EBITDAX (non-GAAP): (in thousands)
Three Months Ended
March 31, 2018Net income (GAAP) $317,401
Interest expense 43,085
Interest income (849)
Income tax expense 98,991
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 130,473
Exploration(1) 12,411
Abandonment and impairment of unproved properties 5,625
Stock-based compensation expense 5,412
Net derivative loss 7,529
Derivative settlement loss (24,528)
Net gain on divestiture activity (385,369)
Other 7
Adjusted EBITDAX (Non-GAAP) $210,188
Interest expense (43,085)
Interest income 849
Income tax expense (98,991)
Exploration(1) (12,411)
Amortization of debt discount and deferred financing costs 3,866
Deferred income taxes 98,366
Other, net (2,534)
Changes in current assets and liabilities (16,113)
Net cash provided by operating activities (GAAP) $140,135
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.
26
ADJUSTED NET INCOME RECONCILIATION
Reconciliation of net income (GAAP) to adjusted net income
(non-GAAP): (in thousands, except per share data)
Three Months Ended
March 31, 2018Net income (GAAP) $317,401
Net derivative loss 7,529
Derivative settlement loss (24,528)
Net gain on divestiture activity (385,369)
Abandonment and impairment of unproved properties 5,625
Other, net 807
Tax effect of adjustments(1) 86,710
Adjusted net income (Non-GAAP) $8,175
Diluted net income per common share (GAAP) $2.81
Net derivative loss 0.07
Derivative settlement loss (0.22)
Net gain on divestiture activity (3.41)
Abandonment and impairment of unproved properties 0.05
Other, net 0.01
Tax effect of adjustments(1) 0.76
Adjusted net income per diluted common share (Non-GAAP) $0.07
Diluted weighted-average common shares outstanding (GAAP): 112,879
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 21.9%, for the three-month period ended March 31, 2018. 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
27
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
March 31, 2018
Net cash provided by operating activities (GAAP): $140.1
Changes in current assets and liabilities 16.1
Exploration(2)(3) 12.4
Discretionary cash flow (Non-GAAP): $168.7
(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
28
DEFINITIONS OF NON-GAAP, FORWARD LOOKING METRICS
The following metrics are forward-looking non-GAAP financial measures. The Company believes these measures are commonly
used in the E&P industry, and other industries, by shareholders, professional research analysts and others in valuation,
comparison and investment recommendations. Certain forward-looking metrics cannot be presented in conjunction with a
reconciliation to the closest GAAP measure, because certain portions of the forecast calculation would are inherently
unpredictable. Accordingly, investors are cautioned not to place undue reliance on these numbers.
1) Projected cash flow per debt adjusted share:
For purposes of forward-looking cash flow from operations, it is not possible to project changes in working capital. The Company calculates
forward-looking cash flow as projected adjusted EBITDAX (reconciled above to GAAP Net Loss and GAAP Net cash provided by operating
activities for actual results) less projected cash interest expense and cash taxes.
The calculation of debt adjusted shares is the sum of average fully diluted common shares outstanding plus the quotient of total principal value
of long-term debt outstanding (including senior notes, convertible stock, credit facility) less cash and cash equivalents divided by the price of
common stock. In the case of the current 2-year plan, the price of common stock used is the closing price at year-end 2017.
2) Capital spend:
For purposes of forward-looking capital spend, it is the sum of projected capital expenditures for drilling and completion of wells, capitalized
geologic and geophysical work, exploration costs excluding dry hole expenses, facilities and infrastructure, allocated overhead and land costs
exclusive of acquisitions.
Capital spend as reported for actual results is reconciled above to GAAP costs incurred in oil and gas activities.
3) Net debt:EBITDAX:
Net debt is total principle value of long-term debt outstanding less cash and cash equivalents. Projected net debt:EBITDAX is projected net debt
divided by projected adjusted EBITDAX. Adjusted EBITDAX is reconciled above to GAAP Net Loss and GAAP Net cash provided by operating
activities for actual results.
4) Discretionary cash flow
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).
