Investor Presentaiton
Endnotes
1) Represents discounted future net cash flows relating to proved oil, natural gas, and NGL reserves based on the standardized measure in ASC Topic 932. Determined using
SEC prices and does not reflect actual prices received or current market prices.
2) Cash and cash equivalents of $140MM as of December 31, 2021. $20MM term loan repaid and credit facility terminated in September 2021.
Management's internal unaudited proved developed reserve PV-10, utilizing forward-looking pricing and other assumptions, do not reflect audited or engineered SEC historical
price-based reserves, as routinely updated from the Company's year-end reserves, consistent with industry practice. Pricing assumptions include March 2, 2022 NYMEX strip
pricing (next twelve months average WTI of $94.08 per Bbl and Henry Hub of $4.90 per Mcf) as well as price realizations and lease operating expense, based on a historical
twelve-month trailing average.
4) Cash and cash equivalents includes restricted cash of $2.3MM as of December 31, 2021.
5) $20MM term loan repaid and credit facility terminated in September 2021.
6)
Based on January 2021 - December 2021; pro forma for NPB sale.
7)
See slide 13 for more details.
8)
Free cash flow for the twelve months ended December 31, 2021. Free cash flow defined as net cash provided by (used in) operating activities plus net cash provided by (used
in) investing activities less the cash flow impact of acquisitions and divestitures.
9) Percentage of the operated PDP well set as of March 2, 2022 that has positive cash flow at $40.00 per Bbl oil, $2.00 per Mcf and NGLS of 40% of WTI; Forecast and expense
assumptions based on YE21 reserves (see endnote 3).
10) Reserves-to-production ratio calculated using YE21 SEC net reserves, divided by 2021 production. Weighted average well life represents the remaining economic well life,
weighted by net reserves, as calculated from 2021 reserves and utilizing forward looking price assumptions, which were based on the March 2, 2022 NYMEX strip (see
endnote 3).
11) References previous "sunk cost" capital investment in Midcon SWD and electrical infrastructure prior to current period; Does not reflect the current value of said infrastructure
as of December 31, 2021, nor future value.
12) $3.90 per Boe for the twelve months ended December 31, 2021 excludes expense workovers; pro forma for NPB divestiture. See slide 10 for more details.
13) Production, LOE, and capex guidance provided to market in August 2021, capex excludes P&A; G&A guidance provided to market in March 2021.
14) 2021 production of 18.6 MBoed includes 36 days of production contribution from NPB assets prior to closing of NPB divestiture in February 2021.
15) Adjusted G&A excludes non-cash stock compensation.
16) Annual production was flat over the trailing twelve months (see endnote 6). Production decline decreased year-over-year from 2020 to 2021. Production decline is relatively
less, based on where the Company's Midcon asset base is in the production cycle, versus that of an asset with a higher density of newer wells that often have high initial
declines.
17) See slide 17 for more details.
18) See slide 14 for more details.
19) Daily production represents a time-normalized cumulative daily rate.
20) As of December 31, 2021.
21) Average performance of existing Meramec producers within one mile of planned 2022 SD drilling locations.
22) Uses average performance at 80.5% NRI.
23) Midcon capital workover projects during the twelve months ended December 31, 2021.
24) SD metrics are Midcon only; pro forma for NPB divestiture. LOE per Boe figures exclude expense workovers.
25) Public SMID Cap peer E&P operators with <70% dry gas production, in alphabetical order, include AMPY, AXAS, BATL, BRY, EPM, ESTE, LPI, REI, REPX, ROCC, TALO,
and WTI. Peers based on 3Q21 annualized per FactSet. SD metric is Midcon only, pro forma for NPB divestiture and reflects FY21.
26) Excluding NW Stack or other properties not connected to saltwater gathering system.
27) Total G&A includes stock-based compensation.
28) Public SMID Cap peer E&P operators with <70% dry gas production, in alphabetical order, include AMPY, AXAS, BATL, BRY, EPM, ESTE, LPI, REI, REPX, ROCC, TALO,
and WTI, based on 3Q21 annualized from FactSet. SD reflects FY21.
29) FCF defined as net cash provided by (used in) operating activities plus net cash provided by (used in) investing activities less the cash flow impact of acquisitions and
divestitures.
18
30) Public SMID Cap peer E&P operators with <70% dry gas production, in alphabetical order, include AMPY, AXAS, BATL, BRY, EPM, ESTE, LPI, REI, REPX, ROCC, TALO,
and WTI, based on 3Q21 YTD from FactSet. SD reflects FY21.
31) Net leverage ratio defined as total debt less cash and cash equivalents divided by last twelve months EBITDA.
32) Midcon only. Without hedge impact. Ethane recovery began in 4Q19, which moves relatively higher BTU.
SandRidge Energy, Inc. NYSE: SDView entire presentation