California Resources Corporation (NYSE: CRC), an independent oil
and natural gas company committed to energy transition in the
sector, today reported third quarter 2022 operational and financial
results.
"CRC's strong financial performance, coupled with our consistent
operational execution, allowed us to increase our fixed dividend by
66% and our Share Repurchase Program by an additional $200 million.
Our disciplined capital allocation and shareholder return strategy
demonstrate our continued commitment to our stakeholders. With
these changes, CRC is on track to deliver nearly $1 billion in
cumulative shareholder returns by year end 2023," said Mac
McFarland, CRC’s President and Chief Executive Officer.
McFarland continued, "On the carbon management side, we continue
to work with emitters, advance our permits, progress our Carbon
TerraVault JV partnership and remain optimistic on our carbon
management goals. CRC's carbon management strategy and energy
transition efforts continue to be a unique differentiator and
support our corporate objectives while delivering on our financial
goals and sustainability targets."
Primary Highlights
- Declared a quarterly dividend of $0.2825 per share of common
stock, totaling ~$20 million payable on December 16, 2022 to
shareholders of record on December 1, 2022, with subsequent
quarterly dividends subject to final determination and Board
approval
- Increased the Share Repurchase Program by $200 million to $850
million from $650 million and extended the term of the program
through December 31, 2023
- Repurchased 1,921,181 common shares for $80 million during the
third quarter of 2022; repurchased an aggregate 10,617,862 shares
for $424 million since the inception of the Share Repurchase
Program through October 31, 2022
- Returned $286 million to shareholders throughout the first
three quarters of 2022, ~5% more than the free cash flow1 generated
during the same period
- Presented three new reservoirs to Carbon TerraVault JV
- Favorable ruling in Kern County EIR Litigation
- Shifted a rig to the Huntington Beach field for a 6 to 8 well
program prioritizing available permits on hand
Third Quarter 2022
Highlights
Financial
- Reported net income of $426 million, or $5.58 per diluted
share. When adjusted for items analysts typically exclude from
estimates including mark-to-market adjustments and gains on asset
divestitures, the Company’s adjusted net income1 was $111 million,
or $1.45 per diluted share
- Generated net cash provided by operating activities of $235
million, adjusted EBITDAX1 of $234 million and free cash flow1 of
$128 million
- Ended the quarter with $358 million of cash on hand, an undrawn
credit facility and $819 million of liquidity2
- Increased available credit under our Reserve Based Lending
Credit Facility by $50 million in the quarter and $110 million year
to date, bringing our aggregate commitments to over $600
million
Operations
- Produced an average of 92,000 net barrels of oil equivalent per
day (Boe/d), including 55,000 barrels of oil per day (Bo/d), with
E&P capital expenditures of $100 million during the
quarter
- Operated three drilling rigs in the San Joaquin Basin and two
drilling rigs in the Los Angeles Basin; drilled 36 wells (42 online
in 3Q22)
- Operated 33 maintenance rigs
2022 Guidance and Capital Program
Update3
CRC's capital program is dynamic in response to oil market
volatility while focusing on oil production and strong liquidity
and maximizing free cash flow. During the third quarter of 2022,
CRC successfully managed the current market inflationary pressures
and is narrowing its 2022 total capital program to the range of
$380 to $400 million. CRC entered the fourth quarter of 2022 with
four drilling rigs and expects to average three drilling rigs for
the remainder of the year in its Elk Hills, Buena Vista, Wilmington
and Huntington Beach fields as CRC repositions for its 2023
program.
This level of expected spending is consistent with CRC's
strategy of investing up to 50% of its operating cash flow back
into CRC's oil and gas operations. Following entry into the Carbon
TerraVault JV with Brookfield, CRC anticipates that a portion of
the operating cash flow previously designated for advancing
decarbonization and other emission reducing projects may become
available for other corporate purposes, such as shareholder returns
and other strategic opportunities (see the summary of our Business
Strategy in Part I, Item 1 & 2 – Business and Properties in
CRC's 2021 Annual Report and see Part I, Item 2 – Management’s
Discussion and Analysis of Financial Condition and Results of
Operations, Carbon TerraVault Joint Venture in the Form 10-Q for
the quarter ended September 30, 2022 for additional details on
Carbon TerraVault JV).
The delay in the Kern County EIR litigation (see Part I, Item 2
– Management’s Discussion and Analysis of Financial Condition and
Results of Operations, Regulatory Update in the Form 10-Q for the
quarter ended September 30, 2022 for additional details on Kern
County EIR) led to a change in CRC's drilling program which favors
a higher natural gas to oil ratio. Therefore, CRC's 2022 oil
production guidance is expected to be negatively impacted by
approximately 1 MBo/d from this change. CRC's 2022 total production
guidance remains consistent with previous expectations in the range
of 91 to 94 MBoe/d.
CRC is raising its operating cost guidance to $760 to $790
million from $725 to $755 million primarily due to higher natural
gas and electricity prices as well as some inflation and the change
in well mix.
CRC GUIDANCE3
Total
2022E
CMB
2022E
E&P, Corp. &
Other
2022E
Net Total Production (MBoe/d)
94 - 91
94 - 91
Net Oil Production (MBbl/d)
58 - 53
58 - 53
Operating Costs ($ millions)
$760 - $790
$760 - $790
CMB Expenses4 ($ millions)
$10 - $20
$10 - $20
Adjusted General and Administrative
Expenses1 ($ millions)
$195 - $210
$10 - $15
$185 - $195
Total Capital ($ millions)
$380 - $400
$20 - $30
$360 - $370
Drilling & Completions
$232 - $235
$232 - $235
Workovers
$36 - $38
$36 - $38
Facilities
$63 - $65
$63 - $65
Corporate & Other
$29 - $32
$29 - $32
CMB
$20 - $30
$20 - $30
Adjusted EBITDAX1 ($ millions)
$835 - $890
($20) - ($35)
$870 -- $910
Free Cash Flow1 ($ millions)
$325 - $370
($40) - ($65)
$390 - $410
Supply Chain and Cost
Inflation
Operating and capital costs in the oil and natural gas industry
are heavily influenced by commodity prices which are typically
cyclical in nature. Typically, suppliers will negotiate increases
for drilling and completion, oilfield services, equipment and
materials as prices for energy-related commodities and raw
materials (such as steel, metals and chemicals) increase. Recent
worldwide and U.S. supply chain issues, together with rising
commodity prices and tight labor markets in the U.S., have created
cost inflation during 2022. Cost inflation may continue into 2023
if rising energy prices result in factory constraints, placing
certain items such as directional drilling components and materials
that have a high energy input intensity in short supply. CRC has
taken measures to limit the effects of the inflationary market by
entering into contracts for materials and services with terms of
one to three years. CRC has also taken steps to build its on-hand
supply stock for items frequently used in its operations to address
possible supply chain disruptions. Despite these efforts, CRC has
experienced significant increased costs thus far in 2022 and
anticipates additional increases in the cost of goods and services
and wages in the company's operations during the remainder of 2022.
These increases will factor into CRC's operating and capital costs
and could also negatively impact its results of operations and cash
flows in 2023 and beyond.
Third Quarter 2022 E&P Operational
Results
In November 2020, the SEC amended Regulation S-K to, among other
things, provide companies with the option to discuss material
changes to results of operations between the current and
immediately preceding quarter. CRC has elected to discuss its
results of operations on a sequential-quarter basis. CRC believes
this approach provides more meaningful and useful information to
measure its performance from the immediately preceding quarter. In
accordance with this final rule, CRC is not required to include a
comparison of the current quarter and the same prior-year
quarter.
Total daily net production for the three months ended September
30, 2022, compared to the three months ended June 30, 2022
increased by approximately 1 MBoe/d, or 1%. This increase is
predominately a result of CRC's production-sharing contracts
(PSCs), which positively impacted its net oil production in the
three months ended September 30, 2022 by approximately 2 MBoe/d,
compared to the three months ended June 30, 2022. This increase was
partially offset by natural decline.
During the third quarter of 2022, CRC operated an average of
three drilling rigs in the San Joaquin Basin and two drilling rigs
in the Los Angeles Basin. During the quarter, CRC drilled 36 net
wells and brought online 42 wells. See Attachment 3 for further
information on CRC's production results by basin and Attachment 5
for further information on CRC's drilling activity.
Third Quarter 2022 Financial
Results
3rd Quarter
2nd Quarter
($ and shares in millions, except per
share amounts)
2022
2022
Statements of
Operations:
Revenues
Total operating revenues
$
1,125
$
747
Operating Expenses
Total operating expenses
536
473
Gain on asset divestitures
2
4
Operating Income
$
591
$
278
Net Income
$
426
$
190
Net income per share - basic
$
5.75
$
2.48
Net income per share - diluted
$
5.58
$
2.41
Adjusted net income1
$
111
$
89
Adjusted net income1 per share -
diluted
$
1.45
$
1.13
Weighted-average common shares outstanding
- basic
74.1
76.7
Weighted-average common shares outstanding
- diluted
76.3
78.8
Adjusted EBITDAX1
$
234
$
204
Review of Third Quarter 2022 Financial
Results
Realized oil prices, excluding the effects of cash settlements
on CRC's commodity derivative contracts, decreased by $14.36 per
barrel from $112.32 per barrel in the second quarter of 2022 to
$97.96 per barrel in the third quarter of 2022. Realized oil prices
were lower in the third quarter of 2022 compared to the second
quarter of 2022 due to slowing global economic activity and ongoing
releases from the U.S. Strategic Petroleum Reserve.
Realized oil prices, including the effects of cash settlements
on CRC's commodity derivative contracts, decreased by $0.72 from
$63.17 in the second quarter of 2022 to $62.45 in the third quarter
of 2022. See Attachment 4 for further information on prices.
Adjusted EBITDAX1 for the third quarter of 2022 was $234
million. See table below for the Company's net cash provided by
operating activities, capital investments and free cash flow1
during the same periods.
FREE CASH FLOW1
Management uses free cash flow, which is
defined by us as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of our net cash provided by operating
activities to free cash flow. We supplemented our non-GAAP measure
of free cash flow with free cash flow of our exploration and
production and corporate items (Free Cash Flow for E&P,
Corporate & Other) which we believe is a useful measure for
investors to understand the results of our core oil and gas
business. We define Free Cash Flow for E&P, Corporate &
Other as consolidated free cash flow less results attributable to
our carbon management business (CMB).
3rd Quarter
2nd Quarter
($ millions)
2022
2022
Net cash provided by operating
activities
$
235
$
181
Capital investments
(107
)
(98
)
Free cash flow1
$
128
$
83
E&P, corporate & other free cash
flow1
$
139
$
98
CMB free cash flow1
$
(11
)
$
(15
)
The following table presents key operating data for CRC's oil
and gas operations, on a per BOE basis, for the periods presented
below. Energy operating costs consist of purchased natural gas used
to generate electricity for CRC's operations and steam for its
steamfloods, purchased electricity and internal costs to generate
electricity used in CRC's operations. Gas processing costs include
costs associated with compression, maintenance and other activities
needed to run CRC's gas processing facilities at Elk Hills.
Non-energy operating costs equal total operating costs less energy
operating costs and gas processing costs. Purchased natural gas
used to generate steam in CRC's steamfloods was reclassified from
non-energy operating costs to energy operating costs beginning in
the third quarter of 2022. All prior periods have been updated to
conform to this presentation.
OPERATING COSTS PER BOE
The reporting of our PSCs creates a
difference between reported operating costs, which are for the full
field, and reported volumes, which are only our net share,
inflating the per barrel operating costs. The following table
presents operating costs after adjusting for the excess costs
attributable to PSCs.
3rd Quarter
2nd Quarter
($ per Boe)
2022
2022
Energy operating costs
$
10.96
9.33
Gas processing costs
0.49
0.54
Non-energy operating costs
13.82
13.05
Operating costs
$
25.27
$
22.92
Excess costs attributable to PSCs
(2.16
)
(2.58
)
Operating costs, excluding effects of PSCs
(a)
$
23.11
$
20.34
(a) Operating costs, excluding effects of
PSCs is a non-GAAP measure.
Energy operating costs for the third quarter of 2022 were $93
million, or $10.96 per Boe, which was an increase of $16 million or
21% from $77 million, or $9.33 per Boe, for the second quarter of
2022. This increase was primarily a result of higher electricity
and natural gas prices.
Non-energy operating costs for the third quarter of 2022 were
$117 million, or $13.82 per Boe, which was an increase of $8
million or 7% from $109 million, or $13.05 per Boe, for the second
quarter of 2022. This increase was primarily a result of increased
downhole maintenance activity.
Kern County Environmental Impact
Report
CalGEM is California's primary regulator of the oil and natural
gas industry on private and state lands, with additional oversight
from the State Lands Commission’s administration of state surface
and mineral interests. CalGEM currently requires an operator to
identify the manner in which the California Environmental Quality
Act (CEQA) has been satisfied prior to issuing various state
permits, typically through either an environmental review or an
exemption by a state or local agency. In Kern County, this
requirement has typically been satisfied by complying with the
local oil and gas ordinance which was supported by an Environmental
Impact Report (EIR) certified by the Kern County Board of
Supervisors in 2015.
A group of petitioners challenged the EIR and on February 25,
2020, a California Appellate Court (the Court) issued a ruling that
required Kern County to decertify the EIR and set aside the amended
Zoning Ordinance. In response, Kern County prepared, circulated and
certified a supplementary recirculated EIR (Supplemental EIR) to
address the ruling from the Court and, in April 2021, resumed
issuing local permits relying on the Supplemental EIR. However, on
October 22, 2021, Kern County was ordered to cease reviewing and
approving oil and gas permits until the trial court determined that
the Zoning Ordinance complies with CEQA requirements. On May 26,
2022, a hearing was held in Kern County and the Court ruled that
Kern County’s local permitting system must cease until the trial
court verified that the noted deficiencies had been remedied and
that the remedies satisfied the concerns raised by the Court. In
October 2022, the trial court ruled that the Supplemental EIR was
not decertified but ordered Kern County to address four discrete
issues before suspension of the local permitting could be lifted,
which, once resolved, would bring the Supplemental EIR into
compliance with applicable laws. The four discrete issues included
requirements for the removal of offsite legacy equipment to
mitigate agricultural land use impacts, revising emission reduction
requirements to address particulate matter, the establishment of a
drinking water grant fund for disadvantaged communities in Kern
County, and updating the local oil and gas ordinance to reflect
these requirements. The Kern County Board of Supervisors approved
these changes in August 2022. On October 12, 2022, Kern County
submitted notice with the trial court of these changes and on
November 2, 2022 the trial court lifted the order preventing
reliance on the local permitting system. This ruling is subject to
further appeal by the petitioners and there is still some potential
for future disruptions to obtaining permits in Kern County until
any such appeals are resolved.
Sustainability Update
In August 2022, CRC published its 2021 Sustainability Report.
The report provides an overview of CRC’s continuous progress on its
sustainability efforts in environmental, social and governance
(ESG) performance as the company advances its commitment to the
energy transition and decarbonization of local economies. Building
off its 2020 Sustainability Update and 2021 Leadership Level
Ranking of A- by CDP, CRC's 2021 Sustainability Report references
Sustainability Accounting Standards Board (SASB), Global Reporting
Initiative (GRI) and International Petroleum Industry Environmental
Conservation Association (IPIECA) standards.
Highlights and achievements from CRC’s 2021 Sustainability
Report include:
- Announced 2045 Full-Scope Net Zero Goal and updated and
expanded ESG goals on methane emissions, freshwater usage,
community giving, diversity in leadership and linked ESG
performance to executive pay
- Hired first Chief Sustainability Officer
- Established Project Management Office of Asset Retirement
Obligations (ARO)
- Advanced CRC's Carbon Management Business including its Carbon
TerraVault carbon capture and storage (CCS) projects, and
CalCapture CCS+ project
- Continued to be a net supplier of both fresh water and
electricity
- Continued to rank among the safest companies in the United
States; workforce achieved a better safety performance rating than
many non-industrial sectors in 2021
- Earned 26 National Safety Achievement Awards in each of its
operating areas and company wide in 2021 for its performance
For more information about CRC’s sustainability efforts and to
download the full length and summary versions of the 2021
Sustainability Report, please visit crc.com/esg.
Balance Sheet and Liquidity
Update
CRC's aggregate commitment under the Revolving Credit Facility
was $602 million as of September 30, 2022. The borrowing base for
the Revolving Credit Facility is redetermined semi-annually and was
reaffirmed at $1.2 billion on October 25, 2022.
As of September 30, 2022, CRC had liquidity of $819 million,
which consisted of $358 million in unrestricted cash and $461
million of available borrowing capacity under its Revolving Credit
Facility which is net of $141 million of letters of credit.
Acquisitions and
Divestitures
During the three and nine months ended September 30, 2022, CRC
recorded a net gain of $2 million and $60 million, respectively,
related to the sale of certain Ventura basin assets and its Lost
Hills transaction. The amount recognized in the three and nine
months ended September 30, 2022 included $2 million and $6 million,
respectively, of additional earn-out consideration on Ventura basin
divestitures that occurred in the second half of 2021 and the first
half of 2022. In addition, CRC also received $2 million to secure
the performance of well abandonment obligations on divested
properties which it expects to return to the purchaser once the
work has been completed. As a result, CRC recorded a liability of
$2 million included as accrued liabilities on its condensed
consolidated balance sheet as of September 30, 2022. See Part II,
Item 8 – Financial Statements and Supplementary Data, Note 3
Divestitures and Acquisitions in CRC's 2021 Annual Report for
additional information on the Ventura basin transactions.
The closing of the sale of CRC's remaining assets in the Ventura
basin is subject to final approval from the State Lands Commission,
which CRC expects to receive prior to the end of the first quarter
of 2023. These remaining assets, consisting of property, plant and
equipment and associated asset retirement obligations, are
classified as held for sale on CRC's condensed consolidated balance
sheet as of September 30, 2022.
Shareholder Return
Strategy
CRC continues to prioritize shareholder returns and dedicates a
portion of its operating cash flow to shareholders. In light of
this strategy, CRC's Board of Directors has increased its Share
Repurchase Program by $200 million to $850 million and extended the
program through December 31, 2023. Adjusting for this increase,
there was approximately $426 million of capacity under CRC's Share
Repurchase Program as of October 31, 2022.
During the third quarter of 2022, CRC repurchased 1.9 million
shares of its common stock for $80 million. Since the inception of
Share Repurchase Program through October 31, 2022, CRC has
repurchased 10.6 million shares for $424 million at an average
price of $39.89 per share, resulting in the repurchase of
approximately 13% of the shares that CRC had at its emergence from
bankruptcy.
On November 2, 2022, CRC's Board of Directors declared a
quarterly cash dividend of $0.2825 per share of common stock. The
dividend is payable to shareholders of record on December 1, 2022,
and will be paid on December 16, 2022.
Through October 31, 2022, CRC has returned $476 million of cash
to shareholders, including $52 million through quarterly dividends
and $424 million through share repurchases.
Upcoming Investor Conference
Participation
CRC's executives will be participating in the following events
in November and December of 2022:
- Furey Research Hidden Gems Conference on November 7 - 8, 2022,
Virtual
- Bank of America Securities Global Energy Conference on November
16 - 17 in Miami, FL
- Goldman Sachs Carbonomics Conference on November 29 in London,
UK
- Capital One Securities Energy Conference on December 7 in
Houston, TX
- StoneX Financial Natural Resources Day on December 8 in New
York, NY
CRC’s presentation materials will be available the day of the
events on the Events and Presentations page in the Investor
Relations section on www.crc.com.
Conference Call Details
To participate in the conference call scheduled for November 3,
2022, at 1:00 p.m. Eastern Time, please dial (877) 328-5505
(International calls please dial +1 (412) 317-5421) or access via
webcast at www.crc.com 15 minutes prior to the scheduled start time
to register. Participants may also pre-register for the conference
call at to https://dpregister.com/sreg/10171364/f48809c260. A
digital replay of the conference call will be archived for
approximately 90 days and supplemental slides for the conference
call will be available online in the Investor Relations section of
www.crc.com.
1 See Attachment 2 for the non-GAAP
financial measures of adjusted EBITDAX, operating costs per BOE
(excluding effects of PSCs), adjusted net income (loss), adjusted
net income (loss) per share - basic and diluted, free cash flow and
free cash flow, after special items including reconciliations to
their most directly comparable GAAP measure, where applicable. For
the full year 2022 estimates of the non-GAAP measures of adjusted
EBITDAX and free cash flow, including reconciliations to their most
directly comparable GAAP measure, see Attachment 7.
2 Calculated as $358 million of available
cash plus $602 million of capacity on CRC's Revolving Credit
Facility less $141 million in outstanding letters of credit.
3 Current guidance assumes a 2022 Brent
price of $99.75 per barrel of oil, NGL realizations as a percentage
of Brent consistent with prior years and a NYMEX gas price of $6.47
per mcf. CRC's share of production under PSC contracts decreases
when commodity prices rise and increases when prices fall.
4 CMB Expenses include start-up
expenditures.
About California Resources
Corporation
California Resources Corporation (CRC) is an independent oil and
natural gas company committed to energy transition in the sector.
CRC has some of the lowest carbon intensity production in the US
and CRC is focused on maximizing the value of our land, mineral and
technical resources for decarbonization by developing CCS and other
emissions reducing projects. For more information about CRC, please
visit www.crc.com. Nothing herein is intended to imply or create a
legal partnership between Brookfield Global Transition Fund,
California Resources Corporation, or any of their respective
subsidiaries and affiliates.
Forward-Looking
Statements
This document contains statements that CRC believes to be
“forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than historical facts
are forward-looking statements, and include statements regarding
CRC's future financial position, business strategy, projected
revenues, earnings, costs, capital expenditures and plans and
objectives of management for the future. Words such as "expect,"
“could,” “may,” "anticipate," "intend," "plan," “ability,”
"believe," "seek," "see," "will," "would," “estimate,” “forecast,”
"target," “guidance,” “outlook,” “opportunity” or “strategy” or
similar expressions are generally intended to identify
forward-looking statements. Such forward-looking statements are
subject to risks and uncertainties that could cause actual results
to differ materially from those expressed in, or implied by, such
statements.
Although CRC believes the expectations and forecasts reflected
in CRC's forward-looking statements are reasonable, they are
inherently subject to numerous risks and uncertainties, most of
which are difficult to predict and many of which are beyond CRC's
control. No assurance can be given that such forward-looking
statements will be correct or achieved or that the assumptions are
accurate or will not change over time. Particular uncertainties
that could cause CRC's actual results to be materially different
than those expressed in CRC's forward-looking statements
include:
- fluctuations in commodity prices and the potential for
sustained low oil, natural gas and natural gas liquids prices;
- equipment, service or labor price inflation or
unavailability;
- legislative or regulatory changes, including those related to
(i) the location, drilling, completion, well stimulation,
operation, maintenance or abandonment of wells or facilities, (ii)
the management of energy, water, land, greenhouse gases (GHGs) or
other emissions, (iii) the protection of health, safety and the
environment, (iv) CRC's ability to claim and utilize tax credits or
other incentives, or (v) the transportation, marketing and sale of
CRC's products and CO2;
- availability or timing of, or conditions imposed on, permits
and approvals necessary for drilling or development activities and
carbon management projects;
- changes in business strategy and CRC's capital plan;
- lower-than-expected production, reserves or resources from
development projects or acquisitions, or higher-than-expected
decline rates;
- incorrect estimates of reserves and related future cash flows
and the inability to replace reserves;
- the recoverability of resources and unexpected geologic
conditions;
- CRC's ability to successfully execute on the construction and
other aspects of the infrastructure projects and enter into third
party contracts on contemplated terms;
- CRC's ability to realize the benefits contemplated by the
business strategies and initiatives related to energy transition,
including carbon capture and storage projects and other renewable
energy efforts;
- CRC's ability to successfully identify, develop and finance
carbon capture and storage projects and other renewable energy
efforts, including those in connection with the Carbon TerraVault
JV;
- global geopolitical, socio-demographic and economic trends and
technological innovations;
- changes in CRC's dividend policy and its ability to declare
future dividends under its debt agreements;
- changes in CRC's share repurchase program and its ability to
repurchase shares under its debt agreements;
- production-sharing contracts' effects on production and
operating costs;
- limitations on CRC's financial flexibility due to existing and
future debt;
- insufficient cash flow to fund CRC's capital plan and other
planned investments, stock repurchases and dividends;
- insufficient capital or lack of liquidity in the capital
markets or inability to attract potential investors;
- limitations on transportation or storage capacity and the need
to shut-in wells;
- inability to enter into desirable transactions, including
acquisitions, asset sales and joint ventures;
- CRC's ability to achieve expected synergies from joint ventures
and acquisitions;
- CRC's ability to utilize its net operating loss carryforwards
to reduce its income tax obligations;
- CRC's ability to successfully gather and verify data regarding
emissions, its environmental impacts and other initiatives;
- the compliance of various third parties with CRC's policies and
procedures and legal requirements as well as contracts it enters
into in connection with CRC's climate-related initiatives;
- the effect of CRC's stock price on costs associated with
incentive compensation;
- changes in the intensity of competition in the oil and gas
industry;
- effects of hedging transactions;
- climate-related conditions and weather events;
- disruptions due to accidents, mechanical failures, power
outages, transportation or storage constraints, natural disasters,
labor difficulties, cyber-attacks or other catastrophic
events;
- pandemics, epidemics, outbreaks, or other public health events,
such as the COVID-19; and
- other factors discussed in Part I, Item 1A – Risk Factors in
CRC's Annual Report on Form 10-K and its other SEC filings
available at www.crc.com.
CRC cautions you not to place undue reliance on forward-looking
statements contained in this document, which speak only as of the
filing date, and CRC undertakes no obligation to update this
information. This document may also contain information from third
party sources. This data may involve a number of assumptions and
limitations, and CRC has not independently verified them and do not
warrant the accuracy or completeness of such third-party
information.
Attachment 1
SUMMARY OF RESULTS
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ and shares in millions, except per
share amounts)
2022
2022
2021
2022
2021
Statements of
Operations:
Revenues
Oil, natural gas and NGL sales
$
680
$
718
$
549
$
2,026
$
1,459
Net gain (loss) from commodity
derivatives
243
(100
)
(125
)
(419
)
(603
)
Sales of purchased natural gas
113
75
95
220
241
Electricity sales
88
49
65
171
131
Other revenue
1
5
4
27
27
Total operating revenues
1,125
747
588
2,025
1,255
Operating Expenses
Operating costs
214
190
190
586
523
General and administrative expenses
59
56
51
163
147
Depreciation, depletion and
amortization
50
50
54
149
160
Asset impairments
—
2
25
2
28
Taxes other than on income
44
42
36
120
113
Exploration expense
1
1
2
3
6
Purchased natural gas expense
98
67
53
186
144
Electricity generation expenses
42
33
29
99
70
Transportation costs
13
12
11
37
37
Accretion expense
10
11
13
32
39
Other operating expenses, net
5
9
4
28
31
Total operating expenses
536
473
468
1,405
1,298
Net gain on asset divestitures
2
4
2
60
4
Operating Income (Loss)
591
278
122
680
(39
)
Non-Operating (Expenses) Income
Reorganization items, net
—
—
(1
)
—
(5
)
Interest and debt expense, net
(13
)
(13
)
(14
)
(39
)
(40
)
Net loss on early extinguishment of
debt
—
—
—
—
(2
)
Other non-operating expenses, net
1
1
—
3
(3
)
Net Income (Loss) Before Income
Taxes
579
266
107
644
(89
)
Income tax provision
(153
)
(76
)
—
(203
)
—
Net income (loss)
426
190
107
441
(89
)
Net income attributable to noncontrolling
interests
—
—
(4
)
—
(13
)
Net Income (Loss) Attributable to
Common Stock
$
426
$
190
$
103
$
441
$
(102
)
Net income (loss) attributable to common
stock per share - basic
$
5.75
$
2.48
$
1.26
$
5.77
$
(1.23
)
Net income (loss) attributable to common
stock per share - diluted
$
5.58
$
2.41
$
1.25
$
5.62
$
(1.23
)
Adjusted net income
$
111
$
89
$
151
$
291
$
331
Adjusted net income per share - basic
$
1.50
$
1.16
$
1.85
$
3.81
$
4.01
Adjusted net income per share -
diluted
$
1.45
$
1.13
$
1.83
$
3.71
$
3.97
Weighted-average common shares outstanding
- basic
74.1
76.7
81.6
76.4
82.6
Weighted-average common shares outstanding
- diluted
76.3
78.8
82.4
78.5
82.6
Adjusted EBITDAX
$
234
$
204
$
242
$
644
$
600
Effective tax rate
26
%
29
%
0
%
32
%
0
%
GAINS AND LOSSES FROM COMMODITY DERIVATIVES
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ millions)
2022
2022
2021
2022
2021
Non-cash derivative gain (loss)
$
425
$
141
$
(26
)
$
185
$
(383
)
Cash payments on settled commodity
derivatives
(182
)
(241
)
(99
)
(604
)
(220
)
Net gain (loss) from commodity
derivatives
$
243
$
(100
)
$
(125
)
$
(419
)
$
(603
)
CAPITAL INVESTMENTS
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ millions)
2022
2022
2021
2022
2021
Facilities
$
20
$
15
$
11
$
52
$
29
Drilling
73
62
32
194
73
Workovers
7
9
8
22
25
Total E&P capital
100
86
51
268
127
CMB
6
10
—
17
—
Corporate and other
1
2
—
19
1
Total capital program
$
107
$
98
$
51
$
304
$
128
Attachment 2
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
To supplement the presentation of its
financial results prepared in accordance with U.S generally
accepted accounting principles (GAAP), management uses certain
non-GAAP measures to assess its financial condition, results of
operations and cash flows. The non-GAAP measures include adjusted
net income (loss), adjusted EBITDAX, adjusted EBITDAX margin,
discretionary cash flow, free cash flow and operating costs per
BOE, among others. These measures are also widely used by the
industry, the investment community and our lenders. Although these
are non-GAAP measures, the amounts included in the calculations
were computed in accordance with GAAP. Certain items excluded from
these non-GAAP measures are significant components in understanding
and assessing our financial performance, such as our cost of
capital and tax structure, as well as the effect of acquisition and
development costs of our assets. Management believes that the
non-GAAP measures presented, when viewed in combination with its
financial and operating results prepared in accordance with GAAP,
provide a more complete understanding of the factors and trends
affecting the Company's performance. The non-GAAP measures
presented herein may not be comparable to other similarly titled
measures of other companies. Below are additional disclosures
regarding each of the non-GAAP measures reported in this press
release, including reconciliations to their most directly
comparable GAAP measure where applicable.
ADJUSTED NET INCOME (LOSS)
Adjusted net income (loss) and adjusted
net income (loss) per share are non-GAAP measures. We define
adjusted net income as net income excluding the effects of
significant transactions and events that affect earnings but vary
widely and unpredictably in nature, timing and amount. These events
may recur, even across successive reporting periods. Management
believes these non-GAAP measures provide useful information to the
industry and the investment community interested in comparing our
financial performance between periods. Reported earnings are
considered representative of management's performance over the long
term. Adjusted net income (loss) is not considered to be an
alternative to net income (loss) reported in accordance with GAAP.
The following table presents a reconciliation of the GAAP financial
measure of net income and net income attributable to common stock
per share to the non-GAAP financial measure of adjusted net income
(loss) and adjusted net income (loss) per share.
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ millions, except per share amounts)
2022
2022
2021
2022
2021
Net income (loss)
$
426
$
190
$
107
$
441
$
(89
)
Net income attributable to noncontrolling
interests
—
—
(4
)
—
(13
)
Net income (loss) attributable to common
stock
426
190
103
441
(102
)
Unusual, infrequent and other items:
Non-cash (income) loss from commodity
derivatives
(425
)
(141
)
26
(185
)
383
Asset impairments
—
2
25
2
28
Reorganization items, net
—
—
1
—
5
Severance and termination costs
—
—
—
—
15
Net loss on early extinguishment of
debt
—
—
—
—
2
Net gain on asset divestitures
(2
)
(4
)
(2
)
(60
)
(4
)
Rig termination expenses
—
—
—
—
2
Other, net
4
2
(2
)
7
2
Total unusual, infrequent and other
items
(423
)
(141
)
48
(236
)
433
Income tax provision of adjustments at
effective tax rate
120
40
—
67
—
Income tax (benefit) provision - out of
period
(12
)
—
—
19
—
Adjusted net income attributable to common
stock
$
111
$
89
$
151
$
291
$
331
Net income (loss) attributable to common
stock per share - basic
$
5.75
$
2.48
$
1.26
$
5.77
$
(1.23
)
Net income (loss) attributable to common
stock per share - diluted
$
5.58
$
2.41
$
1.25
$
5.62
$
(1.23
)
Adjusted net income per share - basic
$
1.50
$
1.16
$
1.85
$
3.81
$
4.01
Adjusted net income per share -
diluted
$
1.45
$
1.13
$
1.83
$
3.71
$
3.97
FREE CASH FLOW
Management uses free cash flow, which is
defined by us as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of our net cash provided by operating
activities to free cash flow. We supplemented our non-GAAP measure
of free cash flow with free cash flow of our exploration and
production and corporate items (Free Cash Flow for E&P,
Corporate & Other) which we believe is a useful measure for
investors to understand the results of our core oil and gas
business. We define Free Cash Flow for E&P, Corporate &
Other as consolidated free cash flow less results attributable to
our carbon management business (CMB).
We have excluded one-time costs for
bankruptcy related fees during 2021 as a supplemental measure of
our free cash flow.
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ millions)
2022
2022
2021
2022
2021
Net cash provided by operating
activities
$
235
$
181
$
182
$
576
$
456
Capital investments
(107
)
(98
)
(51
)
(304
)
(128
)
Free cash flow
128
83
131
272
328
One-time bankruptcy related fees
—
—
1
—
5
Free cash flow, after special items
$
128
$
83
$
132
$
272
$
333
E&P, Corporate and Other Free Cash
Flow
$
139
$
98
$
132
$
301
$
333
CMB Free Cash Flow
$
(11
)
$
(15
)
$
—
$
(29
)
$
—
ADJUSTED EBITDAX
We define Adjusted EBITDAX as earnings
before interest expense; income taxes; depreciation, depletion and
amortization; exploration expense; other unusual, infrequent and
out-of-period items; and other non-cash items. We believe this
measure provides useful information in assessing our financial
condition, results of operations and cash flows and is widely used
by the industry, the investment community and our lenders. Although
this is a non-GAAP measure, the amounts included in the calculation
were computed in accordance with GAAP. Certain items excluded from
this non-GAAP measure are significant components in understanding
and assessing our financial performance, such as our cost of
capital and tax structure, as well as depreciation, depletion and
amortization of our assets. This measure should be read in
conjunction with the information contained in our financial
statements prepared in accordance with GAAP. A version of Adjusted
EBITDAX is a material component of certain of our financial
covenants under our Revolving Credit Facility and is provided in
addition to, and not as an alternative for, income and liquidity
measures calculated in accordance with GAAP.
The following table represents a
reconciliation of the GAAP financial measures of net income and net
cash provided by operating activities to the non-GAAP financial
measure of adjusted EBITDAX. We have supplemented our non-GAAP
measures of consolidated adjusted EBITDAX with adjusted EBITDAX for
our exploration and production and corporate items (Adjusted
EBITDAX for E&P, Corporate & Other) which we believe is a
useful measure for investors to understand the results of our core
oil and gas business.. We define adjusted EBITDAX for E&P,
Corporate & Other as consolidated adjusted EBITDAX less results
attributable to our carbon management business (CMB).
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ millions, except per BOE amounts)
2022
2022
2021
2022
2021
Net income (loss)
$
426
$
190
$
107
$
441
$
(89
)
Interest and debt expense, net
13
13
14
39
40
Depreciation, depletion and
amortization
50
50
54
149
160
Income tax provision
153
76
—
203
—
Exploration expense
1
1
2
3
6
Interest income
(1
)
—
—
(1
)
—
Unusual, infrequent and other items
(a)
(423
)
(141
)
48
(236
)
433
Non-cash items
Accretion expense
10
11
13
32
39
Stock-based compensation
5
4
4
13
10
Post-retirement medical and pension
—
—
—
1
1
Adjusted EBITDAX
$
234
$
204
$
242
$
644
$
600
Net cash used by operating activities
$
235
$
181
$
182
$
576
$
456
Cash interest
23
2
24
48
29
Cash income taxes
—
20
—
20
—
Exploration expenditures
1
1
2
3
6
Working capital changes
(25
)
—
34
(3
)
109
Adjusted EBITDAX
$
234
$
204
$
242
$
644
$
600
E&P, Corporate & Other Adjusted
EBITDAX
$
239
$
209
$
242
$
656
$
600
CMB Adjusted EBITDAX
$
(5
)
$
(5
)
$
—
$
(12
)
$
—
Adjusted EBITDAX per Boe
$
27.63
$
24.61
$
25.83
$
26.06
$
21.85
(a) See Adjusted Net Income (Loss)
reconciliation.
ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES
Management uses a measure called adjusted
general and administrative (G&A) expenses to provide useful
information to investors interested in comparing our costs between
periods and performance to our peers. We supplemented our non-GAAP
measure of adjusted general and administrative expenses with
adjusted general and administrative expenses of our exploration and
production and corporate items (Adjusted General &
Administrative Expenses for E&P, Corporate & Other) which
we believe is a useful measure for investors to understand the
results or our core oil and gas business. We define Adjusted
General & Administrative Expenses for E&P, Corporate &
Other as consolidated adjusted general and administrative expenses
less results attributable to our carbon management business
(CMB).
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ millions)
2022
2022
2021
2022
2021
General and administrative expenses
$
59
$
56
$
51
$
163
$
147
Stock-based compensation
(5
)
(4
)
(4
)
(13
)
(10
)
Other
(1
)
(1
)
—
(2
)
—
Adjusted G&A expenses
$
53
$
51
$
47
$
148
$
137
E&P, Corporate and Other Adjusted
G&A expenses
$
48
$
47
$
47
$
138
$
137
CMB Adjusted G&A expenses
$
5
$
4
$
—
$
10
$
—
OPERATING COSTS PER BOE
The reporting of our PSC-type contracts
creates a difference between reported operating costs, which are
for the full field, and reported volumes, which are only our net
share, inflating the per barrel operating costs. The following
table presents operating costs after adjusting for the excess costs
attributable to PSCs.
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
($ per BOE)
2022
2022
2021
2022
2021
Energy operating costs (1)
$
10.96
$
9.33
$
7.87
$
9.83
$
6.68
Gas processing costs (2)
0.49
0.54
0.56
0.53
0.59
Non-energy operating costs (3)
13.82
13.05
11.85
13.35
11.77
Operating costs
$
25.27
$
22.92
$
20.28
$
23.71
$
19.04
Costs attributable to PSCs
Excess energy operating costs attributable
to PSCs
$
(0.97
)
$
(1.03
)
$
(0.69
)
$
(0.98
)
$
(0.63
)
Excess non-energy operating costs
attributable to PSCs
(1.19
)
(1.55
)
(1.15
)
(1.37
)
(1.09
)
Excess costs attributable to
PSCs
$
(2.16
)
$
(2.58
)
$
(1.84
)
$
(2.35
)
$
(1.72
)
Energy operating costs, excluding effect
of PSCs (1)
$
9.99
$
8.30
$
7.18
$
8.85
$
6.05
Gas processing costs, excluding effect of
PSCs (2)
0.49
0.54
0.56
0.53
0.59
Non-energy operating costs, excluding
effect of PSCs (3)
12.63
11.50
10.70
11.98
10.68
Operating costs, excluding effects of
PSCs
$
23.11
$
20.34
$
18.44
$
21.36
$
17.32
(1) Energy operating costs consist of
purchases of natural gas to generate electricity, purchased
electricity and internal costs to produce electricity used in our
operations.
(2) Gas processing costs include costs
associated with compression, maintenance and other activities
needed to run our gas processing facilities at Elk Hills.
(3) Non-energy operating costs equal total
operating costs less energy and gas processing costs. Purchased
natural gas used to generate steam in our steamfloods was
reclassified from non-energy operating costs to energy operating
costs beginning in the third quarter of 2022. All prior periods
have been updated to conform to this presentation.
Attachment 3
PRODUCTION STATISTICS
Net
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
Oil, NGLs and Natural Gas Production
Per Day
2022
2022
2021
2022
2021
Oil (MBbl/d)
San Joaquin Basin
36
38
40
37
39
Los Angeles Basin
19
16
19
18
19
Ventura Basin
—
—
3
—
3
Total
55
54
62
55
61
NGLs (MBbl/d)
San Joaquin Basin
12
12
13
11
13
Ventura Basin
—
—
—
—
—
Total
12
12
13
11
13
Natural Gas (MMcf/d)
San Joaquin Basin
131
132
135
128
135
Los Angeles Basin
1
1
1
1
1
Ventura Basin
—
—
5
—
5
Sacramento Basin
17
18
19
18
19
Total
149
151
160
147
160
Total Production (MBoe/d)
92
91
102
91
101
Gross Operated and Net
Non-Operated
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
Oil, NGLs and Natural Gas Production
Per Day
2022
2022
2021
2022
2021
Oil (MBbl/d)
San Joaquin Basin
40
42
45
41
44
Los Angeles Basin
26
25
26
26
27
Ventura Basin
—
—
3
—
3
Total
66
67
74
67
74
NGLs (MBbl/d)
San Joaquin Basin
13
13
14
12
13
Ventura Basin
—
—
—
—
1
Total
13
13
14
12
14
Natural Gas (MMcf/d)
San Joaquin Basin
140
141
144
137
143
Los Angeles Basin
7
7
8
7
8
Ventura Basin
—
—
5
—
5
Sacramento Basin
21
22
23
22
24
Total
168
170
180
166
180
Total Production (MBoe/d)
107
108
118
107
118
Note: MBbl/d refers to thousands of
barrels per day; MMcf/d refers to millions of cubic feet per day;
MBoe/d refers to thousands of barrels of oil equivalent (Boe) per
day. Natural gas volumes have been converted to Boe based on the
equivalence of energy content of six thousand cubic feet of natural
gas to one barrel of oil. Barrels of oil equivalence does not
necessarily result in price equivalence.
Attachment 4
PRICE STATISTICS
3rd Quarter
2nd Quarter
3rd Quarter
Nine Months
Nine Months
2022
2022
2021
2022
2021
Oil ($ per Bbl)
Realized price with derivative
settlements
$
62.45
$
63.17
$
55.42
$
61.96
$
54.43
Realized price without derivative
settlements
$
97.96
$
112.32
$
72.89
$
102.01
$
67.62
NGLs ($/Bbl)
$
57.68
$
68.29
$
53.74
$
66.98
$
49.20
Natural gas ($/Mcf)
Realized price with derivative
settlements
$
8.58
$
6.72
$
4.64
$
7.21
$
3.64
Realized price without derivative
settlements
$
8.80
$
6.85
$
4.66
$
7.33
$
3.67
Index Prices
Brent oil ($/Bbl)
$
97.81
$
111.79
$
73.23
$
102.33
$
67.78
WTI oil ($/Bbl)
$
91.56
$
108.41
$
70.56
$
98.09
$
64.82
NYMEX Henry Hub contract month average
($/MMBtu)
$
7.85
$
6.62
$
3.71
$
6.22
$
3.06
NYMEX Henry Hub average monthly settled
price ($/MMBtu)
$
8.20
$
7.17
$
4.01
$
6.77
$
3.18
Realized Prices as Percentage of Index
Prices
Oil with derivative settlements as a
percentage of Brent
64
%
57
%
76
%
61
%
80
%
Oil without derivative settlements as a
percentage of Brent
100
%
100
%
100
%
100
%
100
%
Oil with derivative settlements as a
percentage of WTI
68
%
58
%
79
%
63
%
84
%
Oil without derivative settlements as a
percentage of WTI
107
%
104
%
103
%
104
%
104
%
NGLs as a percentage of Brent
59
%
61
%
73
%
65
%
73
%
NGLs as a percentage of WTI
63
%
63
%
76
%
68
%
76
%
Natural gas with derivative settlements as
a percentage of NYMEX contract month average
109
%
102
%
125
%
116
%
119
%
Natural gas with derivative settlements as
a percentage of NYMEX average monthly settled price
105
%
94
%
116
%
106
%
114
%
Natural gas without derivative settlements
as a percentage of NYMEX contract month average
112
%
103
%
126
%
118
%
120
%
Natural gas without derivative settlements
as a percentage of NYMEX average monthly settled price
107
%
96
%
116
%
108
%
115
%
Attachment 5
THIRD QUARTER 2022 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
9
—
—
—
9
Waterflood
—
11
—
—
11
Steamflood
16
—
—
—
16
Total (1)
25
11
—
—
36
NINE MONTH 2022 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
17
—
—
—
17
Waterflood
27
25
—
—
52
Steamflood
55
—
—
—
55
Total (1)
99
25
—
—
124
(1) Includes steam injectors and drilled
but uncompleted wells, which are not included in the SEC definition
of wells drilled.
Attachment 6
OIL HEDGES AS OF SEPTEMBER 30,
2022
Q4 2022
Q1 2023
Q2 2023
Q3 2023
Q4 2023
2024
Sold Calls
Barrels per day
25,167
18,322
17,837
17,363
5,747
—
Weighted-average Brent price per
barrel
$57.82
$57.28
$60.00
$57.06
$57.06
—
Swaps
Barrels per day
17,263
14,620
14,475
14,697
26,094
1,492
Weighted-average Brent price per
barrel
$58.79
$67.36
$66.36
$66.27
$69.14
$79.06
Net Purchased Puts 1
Barrels per day
25,167
18,322
17,837
17,363
5,747
1,724
Weighted-average Brent price per
barrel
$64.47
$76.25
$76.25
$76.25
$76.25
$75.00
Sold Puts
Barrels per day
1,348
—
—
—
—
—
Weighted-average Brent price per
barrel
$32.00
—
—
—
—
—
1 Purchased and sold puts with the same
strike price have been presented on a net basis.
Attachment 7
2022 Estimated
TOTAL CRC GUIDANCE1
Consolidated
CMB
E&P, Corporate &
Other
Net Total Production (MBoe/d)
94 - 91
94 - 91
Net Oil Production (MBbl/d)
58 - 53
58 - 53
Operating Costs ($ millions)
$760 - $790
$760 - $790
CMB Expenses2 ($ millions)
$10 - $20
$10 - $20
Adjusted General and Administrative
Expenses ($ millions)
$195 - $210
$10 - $15
$185 - $195
Capital ($ millions)
$380 - $400
$20 - $30
$360 - $370
Adjusted EBITDAX ($ millions)
$835 - $890
($20) - ($35)
$870 -- $910
Free Cash Flow ($ millions)
$325 - $370
($40) - ($65)
$390 - $410
See Attachment 2 for management's
disclosure of its use of these non-GAAP measures and how these
measures provide useful information to investors about CRC's
results of operations and financial condition. CRC has supplemented
its non-GAAP measures of consolidated adjusted EBITDAX and
consolidated free cash flow with adjusted EBITDAX for its
exploration and production and corporate items (Adjusted EBITDAX
for E&P, Corporate & Other) and free cash flow from our
exploration and production and corporate items (free cash flow from
E&P, Corporate & Other) which CRC believes are useful
measures for investors to understand the results of its core oil
and gas business. CRC defines adjusted EBITDAX for E&P,
Corporate & Other as consolidated adjusted EBITDAX less results
attributable to its carbon management business (CMB). CRC defines
free cash flow from E&P, Corporate & Other as consolidated
free cash flow less results attributable to CMB.
2022 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
Net cash provided (used) by operating
activities
$
725
$
750
$
(35
)
$
(20
)
$
760
$
770
Capital investments
(400
)
(380
)
(30
)
(20
)
(370
)
(360
)
Estimated free cash flow
$
325
$
370
$
(65
)
$
(40
)
$
390
$
410
2022 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
Net income
$
612
$
650
$
(35
)
$
(20
)
$
647
$
670
Interest and debt expense, net
51
52
51
52
Depreciation, depletion and
amortization
200
202
200
202
Exploration expense
5
10
5
10
Income taxes
273
277
273
277
Unusual, infrequent and other items
Non-cash derivative gain
(318
)
(315
)
(318
)
(315
)
Gain on asset divestitures
(60
)
(60
)
(60
)
(60
)
Other
10
10
10
10
Other non-cash items
Accretion expense
43
44
43
44
Stock-based compensation
17
18
17
18
Post-retirement medical and pension
2
2
2
2
Estimated adjusted EBITDAX
$
835
$
890
$
(35
)
$
(20
)
$
870
$
910
Net cash provided (used) by operating
activities
$
725
$
750
$
(35
)
$
(20
)
$
760
$
770
Cash interest
50
52
50
52
Cash income taxes
30
36
30
36
Exploration expenditures
5
10
5
10
Working capital changes
25
42
25
42
Estimated adjusted EBITDAX
$
835
$
890
$
(35
)
$
(20
)
$
870
$
910
2022 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
General and administrative expenses
$
220
$
230
$
10
$
15
$
210
$
215
Equity-settled stock-based
compensation
(20
)
(15
)
(20
)
(15
)
Other
(5
)
(5
)
(5
)
(5
)
Adjusted general and administrative
expenses
$
195
$
210
$
10
$
15
$
185
$
195
1 Current guidance assumes a 2022 Brent
price of $99.75 per barrel of oil, NGL realizations as a percentage
of Brent consistent with prior years and a NYMEX gas price of $6.47
per mcf. CRC's share of production under PSC contracts decreases
when commodity prices rise and increases when prices fall.
2 CMB Expenses include start-up
expenditures.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20221102005748/en/
Joanna Park (Investor Relations) 818-661-3731
Joanna.Park@crc.com
Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com
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