California Resources Corporation (NYSE: CRC) today reported
financial and operating results for the fourth quarter and full
year 2024, as well as its guidance for 2025. The Company plans to
host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on
Monday, March 3, 2025. Participation details can be found within
this release. Supplemental slides are available on CRC’s website at
www.crc.com.
Fourth Quarter 2024
Highlights
- Generated $206 million of net cash
flow provided by operating activities, $258 million of operating
cash flow before changes in operating assets and liabilities¹ and
$118 million in free cash flow¹
- Reported net income of $33 million,
adjusted net income¹ of $84 million and adjusted EBITDAX¹ of $316
million
- Delivered average net production of
141 thousand barrels of oil equivalent per day (MBoe/d) (79% oil);
exited 2024 with 163 MBoe/d of gross production
- Returned $92 million to
shareholders (~78% of fourth quarter free cash flow¹) via share
repurchases and dividends2
- Received California’s first
Environmental Protection Agency (EPA) Class VI well permits for
underground carbon dioxide (CO2) injection and storage into the 26R
reservoir. See Carbon TerraVault’s 2024 Update for additional
information
Full Year 2024 Highlights
- Transformed and scaled the business
through successful Aera merger, and achieved more than 70% of its
targeted $235 million in merger-related synergies
- Generated net cash flow provided by
operating activities of $610 million, $707 million before changes
in operating assets and liabilities1 and $355 million in free cash
flow¹
- Posted net income of $376 million,
adjusted net income¹ of $317 million and adjusted EBITDAX¹ of
$1,006 million
- Delivered average net production of
110 MBoe/d (73% oil)
- Enhanced capital efficiency after
deploying $123 million of drilling, completions and workover
capital to achieve an entry-to-exit gross production decline of
approximately 6%
- Returned $303 million to
shareholders (approximately 85% of free cash flow¹) via share
repurchases and dividends2
- Exited 2024 with $354 million in
available cash3, $983 million in available borrowing capacity and
liquidity1 of $1,337 million3
- Sold 0.9 acre Fort Apache real
estate property in Huntington Beach for approximately $10
million
- Signed new CO2 management
agreements4 (CDMA) and memoranda of understanding4 (MOU) to
sequester up to 5.4 million metric tons per annum (MMTPA) of CO2
emissions with reputable national partners and approved
California’s first carbon capture and storage (CCS) project. See
Carbon TerraVault’s 2024 Update for additional information
2025 Outlook and Highlights
- Capital investments expected to
range between $285 - $335 million, including drilling, completions
and workover capital of $165 - $180 million and carbon management
capital of $20 - $30 million
- Net production expected to be 132 -
138 MBoe/d (79% oil), with an expected range between 5% – 8%
entry-to-exit gross production decline
- On track to achieve the remaining
$65 million in Aera-related synergies by year-end
- Redeemed $123 million of 2026
Senior Notes at par in February 2025 with the remaining balance of
$122 million slated for redemption later this year
- Announced a new up to 1.0 MMTPA of
CO2 emissions brownfield MOU4 with National Cement Company of
California Inc. (National Cement); Targeting first CO₂
sequestration and cash flow from CCS project at Elk Hills Cryogenic
Gas Plant. See Carbon TerraVault and National Cement Sign MOU for
California’s First Net Zero Cement Facility for additional
information
“We delivered exceptional results in 2024, while
successfully completing our transformative merger with Aera Energy.
We proved our ability to seamlessly integrate assets and drive
synergies. Today, we have the right people, portfolio, and business
plan to help lead California’s decarbonization efforts,” said CRC
President and CEO Francisco Leon. “In 2025, we are focused on
delivering value through our integrated asset portfolio, combining
conventional oil and gas, carbon management and an expanding power
solutions business. We will maintain financial strength to generate
sustainable cash flow, while returning significant capital through
dividends and opportunistic share buybacks to our
shareholders.”
Fourth Quarter and Full Year 2024
Financial Results
Selected Production, Price Information and Results of
Operations |
4th Quarter |
|
|
3rd Quarter |
|
|
Total Year |
|
|
Total Year |
($ in millions) |
2024 |
|
|
2024 |
|
|
2024 |
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
Net oil production per day (MBbl/d) |
|
112 |
|
|
|
|
113 |
|
|
|
80 |
|
|
|
52 |
|
Realized oil price with derivative settlements ($ per Bbl) |
$ |
73.00 |
|
|
|
$ |
75.38 |
|
|
$ |
75.66 |
|
|
$ |
65.97 |
|
Net NGL production per day
(MBbl/d) |
|
10 |
|
|
|
|
11 |
|
|
|
10 |
|
|
|
11 |
|
Realized NGL price ($ per Bbl) |
$ |
52.62 |
|
|
|
$ |
45.77 |
|
|
$ |
48.93 |
|
|
$ |
48.94 |
|
Net natural gas production per
day (MMcf/d) |
|
115 |
|
|
|
|
126 |
|
|
|
117 |
|
|
|
135 |
|
Realized natural gas price with derivative settlements ($ per
Mcf) |
$ |
3.65 |
|
|
|
$ |
2.68 |
|
|
$ |
2.99 |
|
|
$ |
8.59 |
|
Net total production per day
(MBoe/d) |
|
141 |
|
|
|
|
145 |
|
|
|
110 |
|
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
|
Margin from purchased
commodities5 ($ millions) |
$ |
6 |
|
|
|
$ |
8 |
|
|
$ |
42 |
|
|
$ |
183 |
|
Electricity margin6 ($
millions) |
$ |
30 |
|
|
|
$ |
60 |
|
|
$ |
119 |
|
|
$ |
108 |
|
Net gain from commodity
derivatives ($ millions) |
$ |
(49 |
) |
|
|
$ |
356 |
|
|
$ |
241 |
|
|
$ |
(12 |
) |
Selected Financial Statement Data and non-GAAP
measures: |
4th Quarter |
|
|
3rd Quarter |
|
|
Total Year |
|
|
Total Year |
($ and
shares in millions, except per share amounts) |
2024 |
|
|
2024 |
|
|
2024 |
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
Statements of
Operations: |
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
$ |
877 |
|
|
|
$ |
1,353 |
|
|
|
$ |
3,198 |
|
|
|
$ |
2,801 |
|
|
|
|
|
|
|
|
|
|
|
|
Selected
Expenses |
|
|
|
|
|
|
|
|
|
|
Operating costs |
$ |
323 |
|
|
|
$ |
311 |
|
|
|
$ |
966 |
|
|
|
$ |
822 |
|
General and administrative
expenses |
$ |
95 |
|
|
|
$ |
106 |
|
|
|
$ |
321 |
|
|
|
$ |
267 |
|
Adjusted general and administrative expenses1 |
$ |
85 |
|
|
|
$ |
89 |
|
|
|
$ |
279 |
|
|
|
$ |
218 |
|
Taxes other than on
income |
$ |
80 |
|
|
|
$ |
85 |
|
|
|
$ |
242 |
|
|
|
$ |
165 |
|
Transportation costs |
$ |
21 |
|
|
|
$ |
23 |
|
|
|
$ |
81 |
|
|
|
$ |
67 |
|
Operating
Income |
$ |
68 |
|
|
|
$ |
518 |
|
|
|
$ |
620 |
|
|
|
$ |
808 |
|
Interest and debt expense |
$ |
(28 |
) |
|
|
$ |
(29 |
) |
|
|
$ |
(87 |
) |
|
|
$ |
(56 |
) |
Income tax (provision)
benefit |
$ |
(8 |
) |
|
|
$ |
(138 |
) |
|
|
$ |
(140 |
) |
|
|
$ |
(184 |
) |
Net
income |
$ |
33 |
|
|
|
$ |
345 |
|
|
|
$ |
376 |
|
|
|
$ |
564 |
|
|
|
|
|
|
|
|
|
|
|
|
EPS, Non-GAAP Measures
and Select Balance Sheet Data |
|
|
|
|
|
|
|
|
|
|
Adjusted net income1 |
$ |
84 |
|
|
|
$ |
137 |
|
|
|
$ |
317 |
|
|
|
$ |
372 |
|
Weighted-average common shares
outstanding - diluted |
|
92.2 |
|
|
|
|
91.2 |
|
|
|
|
81.4 |
|
|
|
|
72.5 |
|
Net income per share -
diluted |
$ |
0.36 |
|
|
|
$ |
3.78 |
|
|
|
$ |
4.62 |
|
|
|
$ |
7.78 |
|
Adjusted net income1 per share
- diluted |
$ |
0.91 |
|
|
|
$ |
1.50 |
|
|
|
$ |
3.89 |
|
|
|
$ |
5.13 |
|
Adjusted EBITDAX1 |
$ |
316 |
|
|
|
$ |
402 |
|
|
|
$ |
1,006 |
|
|
|
$ |
862 |
|
Net cash provided by operating
activities |
$ |
206 |
|
|
|
$ |
220 |
|
|
|
$ |
610 |
|
|
|
$ |
653 |
|
Net cash provided by operating
activities before changes in operating assets and liabilities,
net1 |
$ |
258 |
|
|
|
$ |
249 |
|
|
|
$ |
707 |
|
|
|
$ |
647 |
|
Capital investments |
$ |
88 |
|
|
|
$ |
79 |
|
|
|
$ |
255 |
|
|
|
$ |
185 |
|
Free cash flow1 |
$ |
118 |
|
|
|
$ |
141 |
|
|
|
$ |
355 |
|
|
|
$ |
468 |
|
Cash and cash equivalents |
$ |
372 |
|
|
|
$ |
1,031 |
|
|
|
$ |
372 |
|
|
|
$ |
496 |
|
|
2024 Proved Reserves
As of December 31, 2024, CRC’s total proved
reserves were 545 million Boe (MMBoe), of which approximately 81%
was oil and 506 MMBoe was proved developed. CRC added 236 MMBoe of
proved reserves related to the Aera merger in 2024. Estimated
future net cash flows had a PV-101 value of $8,877 million based on
SEC pricing of Brent spot price of $80.42 per barrel of oil and
NYMEX gas price of $2.13 per MMBtu for natural gas. See Attachment
3 for complete information on CRC’s Non-GAAP Financial Measures and
Reconciliations.
2025 Guidance
The following table provides key first quarter
and full year 2025 financial and operating guidance. CRC expects to
run a one rig program in the first half of 2025, increasing to two
rigs in the second half of 2025. See Attachment 2 for complete
information on CRC’s first quarter and full year 2025 guidance.
CRC Guidance7 |
1Q25E |
Total Year2025E |
Net Production (MBoe/d) |
138 - 142 |
132 - 138 |
Net Oil Production (%) |
~79% |
~79% |
Capital ($ millions) |
$60 - $70 |
$285 - $335 |
Adjusted EBITDAX1 ($ millions) |
$275 - $295 |
$1,100 - $1,200 |
|
|
|
Shareholder Returns and Dividend
Announcements
CRC is committed to sustainably returning cash
to shareholders through dividends and repurchases of its
outstanding common stock. Since mid-2021, the Company has returned
approximately $1,060 million to shareholders2, including $793
million in share repurchases and $267 million in dividends.
In 2024, CRC repurchased 3.6 million shares of
its common stock for $190 million2 at an average price of $52.12
per share and returned $113 million to shareholders in dividends.
As of December 31, 2024, CRC had approximately $557 million of
capacity remaining under its share repurchase authorization.
On March 2, 2025, CRC’s Board of Directors
declared a quarterly cash dividend of $0.3875 per share of common
stock, payable to shareholders of record on March 10, 2025. The
dividend is expected to be paid on March 21, 2025.
Balance Sheet and Liquidity
In November 2024, CRC reaffirmed its
$1,500 million borrowing base under its Revolving Credit
Facility (the Facility), extended its maturity date to March 16,
2029, amended the springing maturity to allow the 2026 Senior Notes
to remain outstanding past October 31, 2025 subject to certain
conditions, and increased elected commitments by $50 million, as
well as other technical amendments.
At year-end 2024, CRC had $354 million in
available cash and cash equivalents3, $983 million of available
borrowing capacity under its Facility (which reflects $1,150
million of borrowing capacity less $167 million of outstanding
letters of credit) and liquidity1 of $1,337 million3.
2024 Sustainability Highlights
“In 2024, CRC demonstrated its unwavering
commitment to sustainability by achieving significant milestones in
environmental stewardship, safety, and community engagement,” said
Leon. “We are proud that our assets in the Los Angeles Basin were
MiQ 'Grade A' certified, and we plan to continue investing in the
Kern County community through our Community Benefits Plan. These
are just two examples of our dedication to the communities and
areas where we live and work.”
- Achieved a 'Grade A' certification
from MiQ for methane emissions performance in the Los Angeles
Basin, marking the first such certification for oil and gas
operations in California and the Rocky Mountain region.
- Eliminated 311 gas venting
pneumatics, aligning with 2030 methane reduction goals and
demonstrating a proactive approach to minimizing environmental
impact by reducing methane emissions by over 260 metric tons per
year.
- Delivered more than 112 million
barrels of water for agricultural use, exceeding internal
consumption and supporting local agriculture.
- Launched the Carbon TerraVault I
Elk Hills Community Benefits Plan, committing 1% of each project
investment toward programs and partnerships that provide
transformative benefits to local communities in Kern County.
Upcoming Investor Conference
Participation
CRC will be participating in the following
events in March 2025:
- DEP THRIVE Energy Conference on
March 5 in Houston, TX
- Morgan Stanley Global Energy &
Power Conference on March 6 in New York, NY
- CERAWeek 2025 on March 10 to 12 in
Houston, TX
- 37th Annual ROTH Conference on
March 17 in Dana Point, CA
- 2025 NYSE Investor Access Day on
March 20, Virtual
CRC’s presentation materials will be available
on the day of the event on its website. See the Events and
Presentations page under the Investor Relations section on
www.crc.com.
Conference Call Details
A conference call and webcast is planned for 1
p.m. ET (10 a.m. PT) on Monday, March 3, 2025. To participate in
the call, dial (877) 328-5505 (International calls dial +1 (412)
317-5421) or access via webcast at www.crc.com. Participants may
also pre-register for the conference call at
https://dpregister.com/sreg/10194600/fe015c8aa0. A digital replay
of the conference call will be available for approximately 90
days.
1 See Attachment 3 for the non-GAAP financial
measures of operating costs per BOE (excluding effects of PSCs),
adjusted net income (loss), adjusted net income (loss) per share -
basic and diluted, net cash provided by operating activities before
changes in operating assets and liabilities, net, adjusted EBITDAX,
free cash flow, adjusted general and administrative expenses and
capital efficiency including reconciliations to their most directly
comparable GAAP measure, where applicable. See Attachment 2 for the
1Q25 and 2025 estimates of the non-GAAP measures of adjusted
EBITDAX and adjusted general and administrative expenses, including
reconciliations to its most directly comparable GAAP measure.2 The
total value of shares purchased includes approximately
$2 million and $1 million in both the years ended
December 31, 2024 and 2023 related to excise taxes on share
repurchases, which was effective beginning in 2023. Commissions
paid were not significant in all periods presented. 3 Excludes
restricted cash of $18 million.4 MOUs and CDMAs are
non-binding agreements. The projects and transactions described in
an MOU or CDMA are subject to certain conditions precedent,
typically including the negotiation of definitive documents, a
final investment decision by the parties and receipt of EPA Class
VI permits and other regulatory approvals. 5 Margin from
purchased commodities is calculated as the difference between
revenue from purchased commodities and costs related to purchased
commodities, and excludes costs of transportation.6 Electricity
margin is calculated as the difference between electricity sales
and electricity generation expenses.7 1Q25 guidance assumes Brent
price of $76.54 per barrel of oil, NGL realizations as a percentage
of Brent consistent with prior years and a NYMEX gas price of $3.38
per mcf. Total year 2025 guidance assumes Brent price of $73.05 per
barrel of oil, NGL realizations as a percentage of Brent consistent
with prior years and a NYMEX gas price of $3.49 per mcf. CRC’s
share of production under PSC contracts decreases when commodity
prices rise and increases when prices fall.
About California Resources Corporation
California Resources Corporation (CRC) is an
independent energy and carbon management company committed to
energy transition. CRC is committed to environmental stewardship
while safely providing local, responsibly sourced energy. CRC is
also focused on maximizing the value of its land, mineral
ownership, and energy expertise for decarbonization by developing
CCS and other emissions reducing projects. For more information
about CRC, please visit www.crc.com.
About Carbon TerraVault
Carbon TerraVault (CTV), CRC’s carbon management
business, is developing services to capture, transport and
permanently store CO2 for its customers. CTV is engaged in a series
of proposed CCS projects that if developed will inject CO2 captured
from industrial sources into depleted reservoirs deep underground
for permanent sequestration. For more information, visit
carbonterravault.com.
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. Additionally, the information in this
report contains forward-looking statements related to the recently
announced Aera merger.
Although CRC believes the expectations and
forecasts reflected in its 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 its 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 its forward-looking
statements include:
- fluctuations in commodity prices,
including supply and demand considerations for CRC’s products and
services, and the impact of such fluctuations on revenues and
operating expenses;
- decisions as to production levels
and/or pricing by OPEC or U.S. producers in future periods;
- government policy, war and
political conditions and events, including the military conflicts
in Israel, Lebanon, Ukraine and the Middle East;
- the ability to successfully execute
integration efforts in connection with the Aera Merger, and achieve
projected synergies and ensure that such synergies are
sustainable;
- regulatory actions and changes that
affect the oil and gas industry generally and us in particular,
including (1) the availability or timing of, or conditions imposed
on, EPA and other governmental permits and approvals necessary for
drilling or development activities or its carbon management
segment; (2) the management of energy, water, land, greenhouse
gases (GHGs) or other emissions, (3) the protection of health,
safety and the environment, or (4) the transportation, marketing
and sale of its products;
- the efforts of activists to delay
prevent oil and gas activities or the development of CRC’s carbon
management segment through a variety of tactics, including
litigation;
- the impact of inflation on future
expenses and changes generally in the prices of goods and
services;
- changes in business strategy and
capital plan;
- lower-than-expected production or
higher-than-expected production decline rates;
- changes to estimates of reserves
and related future cash flows, including changes arising from CRC’s
inability to develop such reserves in a timely manner, and any
inability to replace such reserves;
- the recoverability of resources and
unexpected geologic conditions;
- general economic conditions and
trends, including conditions in the worldwide financial, trade and
credit markets;
- production-sharing contracts'
effects on production and operating costs;
- the lack of available equipment,
service or labor price inflation;
- limitations on transportation or
storage capacity and the need to shut-in wells;
- any failure of risk
management;
- results from operations and
competition in the industries in which it operates;
- CRC’s ability to realize the
anticipated benefits from prior or future efforts to reduce
costs;
- environmental risks and liability
under federal, regional, state, provincial, tribal, local and
international environmental laws and regulations (including
remedial actions);
- the creditworthiness and
performance of its counterparties, including financial
institutions, operating partners, CCS project participants and
other parties;
- reorganization or restructuring of
its operations;
- CRC’s ability to claim and utilize
tax credits or other incentives in connection with our CCS
projects;
- CRC’s ability to realize the
benefits contemplated by its energy transition strategies and
initiatives, including CCS 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, and its ability to convert CDMAs to
definitive agreements and enter into other offtake agreements;
- CRC’s ability to maximize the value
of its carbon management segment and operate it on a stand alone
basis;
- CRC’s ability to successfully
develop infrastructure projects and enter into third party
contracts on contemplated terms;
- uncertainty around the accounting
of emissions and its ability to successfully gather and verify
emissions data and other environmental impacts;
- changes to CRC’s dividend policy
and share repurchase program, and its ability to declare future
dividends or repurchase shares under its debt agreements;
- limitations on CRC’s financial
flexibility due to existing and future debt;
- insufficient cash flow to fund its
capital plan and other planned investments and return capital to
shareholders;
- changes in interest rates;
- CRC’s access to and the terms of
credit in commercial banking and capital markets, including its
ability to refinance debt or obtain separate financing for its
carbon management segment;
- changes in state, federal or
international tax rates, including CRC’s ability to utilize its net
operating loss carryforwards to reduce its income tax
obligations;
- effects of hedging
transactions;
- the effect of CRC’s stock price on
costs associated with incentive compensation;
- inability to enter into desirable
transactions, including joint ventures, divestitures of oil and
natural gas properties and real estate, and acquisitions, and its
ability to achieve any expected synergies;
- disruptions due to earthquakes,
forest fires, floods, extreme weather events or other natural
occurrences, accidents, mechanical failures, power outages,
transportation or storage constraints, labor difficulties,
cybersecurity breaches or attacks or other catastrophic
events;
- pandemics, epidemics, outbreaks, or
other public health events, such as the COVID-19 pandemic; and
- other factors discussed in Part I,
Item 1A – Risk Factors.
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 does not warrant the accuracy or completeness of such
third-party information.
Contacts:
Joanna Park (Investor
Relations)818-661-3731Joanna.Park@crc.com |
Richard Venn (Media)818-661-6014 Richard.Venn@crc.com |
|
|
Attachment 1 |
SUMMARY OF
RESULTS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ and
shares in millions, except per share amounts) |
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
Statements of
Operations: |
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
Oil, natural gas and NGL sales |
$ |
826 |
|
|
$ |
870 |
|
|
$ |
483 |
|
|
$ |
2,537 |
|
|
$ |
2,155 |
|
Net (loss) gain from commodity
derivatives |
|
(49 |
) |
|
|
356 |
|
|
|
119 |
|
|
|
24 |
|
|
|
(12 |
) |
Revenue from marketing of
purchased commodities |
|
59 |
|
|
|
51 |
|
|
|
71 |
|
|
|
235 |
|
|
|
407 |
|
Electricity sales |
|
39 |
|
|
|
69 |
|
|
|
42 |
|
|
|
159 |
|
|
|
211 |
|
Interest and other
revenue |
|
2 |
|
|
|
7 |
|
|
|
11 |
|
|
|
26 |
|
|
|
40 |
|
Total operating revenues |
|
877 |
|
|
|
1,353 |
|
|
|
726 |
|
|
|
3,198 |
|
|
|
2,801 |
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses |
|
|
|
|
|
|
|
|
|
Operating costs |
|
323 |
|
|
|
311 |
|
|
|
186 |
|
|
|
966 |
|
|
|
822 |
|
General and administrative
expenses |
|
95 |
|
|
|
106 |
|
|
|
66 |
|
|
|
321 |
|
|
|
267 |
|
Depreciation, depletion and
amortization |
|
142 |
|
|
|
140 |
|
|
|
55 |
|
|
|
388 |
|
|
|
225 |
|
Asset impairment |
|
1 |
|
|
|
— |
|
|
|
— |
|
|
|
14 |
|
|
|
3 |
|
Taxes other than on
income |
|
80 |
|
|
|
85 |
|
|
|
33 |
|
|
|
242 |
|
|
|
165 |
|
Costs related to marketing of
purchased commodities |
|
53 |
|
|
|
43 |
|
|
|
42 |
|
|
|
193 |
|
|
|
224 |
|
Electricity generation
expenses |
|
9 |
|
|
|
9 |
|
|
|
18 |
|
|
|
40 |
|
|
|
103 |
|
Transportation costs |
|
21 |
|
|
|
23 |
|
|
|
18 |
|
|
|
81 |
|
|
|
67 |
|
Accretion expense |
|
31 |
|
|
|
31 |
|
|
|
11 |
|
|
|
87 |
|
|
|
46 |
|
Net loss on natural gas
purchase derivatives |
|
19 |
|
|
|
9 |
|
|
|
8 |
|
|
|
30 |
|
|
|
8 |
|
Carbon management business
expenses |
|
20 |
|
|
|
13 |
|
|
|
17 |
|
|
|
56 |
|
|
|
37 |
|
Measurement period
adjustments |
|
(12 |
) |
|
|
— |
|
|
|
— |
|
|
|
(12 |
) |
|
|
— |
|
Other operating expenses,
net |
|
31 |
|
|
|
65 |
|
|
|
14 |
|
|
|
183 |
|
|
|
58 |
|
Total operating expenses |
|
813 |
|
|
|
835 |
|
|
|
468 |
|
|
|
2,589 |
|
|
|
2,025 |
|
Net gain on asset
divestitures |
|
4 |
|
|
|
— |
|
|
|
25 |
|
|
|
11 |
|
|
|
32 |
|
Operating
Income |
|
68 |
|
|
|
518 |
|
|
|
283 |
|
|
|
620 |
|
|
|
808 |
|
|
|
|
|
|
|
|
|
|
|
Non-Operating
(Expenses) Income |
|
|
|
|
|
|
|
|
|
Interest and debt expense |
|
(28 |
) |
|
|
(29 |
) |
|
|
(13 |
) |
|
|
(87 |
) |
|
|
(56 |
) |
Loss from investment in
unconsolidated subsidiaries |
|
(1 |
) |
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(10 |
) |
|
|
(9 |
) |
Loss on early extinguishment
of debt |
|
— |
|
|
|
(5 |
) |
|
|
(1 |
) |
|
|
(5 |
) |
|
|
(1 |
) |
Other non-operating income
(loss), net |
|
2 |
|
|
|
1 |
|
|
|
1 |
|
|
|
(2 |
) |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
Income Before Income
Taxes |
|
41 |
|
|
|
483 |
|
|
|
267 |
|
|
|
516 |
|
|
|
748 |
|
Income tax (provision) |
|
(8 |
) |
|
|
(138 |
) |
|
|
(79 |
) |
|
|
(140 |
) |
|
|
(184 |
) |
Net
Income |
$ |
33 |
|
|
$ |
345 |
|
|
$ |
188 |
|
|
$ |
376 |
|
|
$ |
564 |
|
|
|
|
|
|
|
|
|
|
|
Net income per share -
basic |
$ |
0.36 |
|
|
$ |
3.86 |
|
|
$ |
2.74 |
|
|
$ |
4.74 |
|
|
$ |
8.10 |
|
Net income per share -
diluted |
$ |
0.36 |
|
|
$ |
3.78 |
|
|
$ |
2.60 |
|
|
$ |
4.62 |
|
|
$ |
7.78 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income |
$ |
84 |
|
|
$ |
137 |
|
|
$ |
67 |
|
|
$ |
317 |
|
|
$ |
372 |
|
Adjusted net income per share
- basic |
$ |
0.93 |
|
|
$ |
1.53 |
|
|
$ |
0.98 |
|
|
$ |
4.00 |
|
|
$ |
5.34 |
|
Adjusted net income per share
- diluted |
$ |
0.91 |
|
|
$ |
1.50 |
|
|
$ |
0.93 |
|
|
$ |
3.89 |
|
|
$ |
5.13 |
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares
outstanding - basic |
|
90.8 |
|
|
|
89.4 |
|
|
|
68.7 |
|
|
|
79.3 |
|
|
|
69.6 |
|
Weighted-average common shares
outstanding - diluted |
|
92.2 |
|
|
|
91.2 |
|
|
|
72.3 |
|
|
|
81.4 |
|
|
|
72.5 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX |
$ |
316 |
|
|
$ |
402 |
|
|
$ |
179 |
|
|
$ |
1,006 |
|
|
$ |
862 |
|
Effective tax rate |
|
20 |
% |
|
|
29 |
% |
|
|
30 |
% |
|
|
27 |
% |
|
|
25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($ in
millions) |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Cash Flow
Data: |
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
206 |
|
|
$ |
220 |
|
|
$ |
131 |
|
|
$ |
610 |
|
|
$ |
653 |
|
Net cash used in investing
activities |
$ |
(67 |
) |
|
$ |
(928 |
) |
|
$ |
(42 |
) |
|
$ |
(1,077 |
) |
|
$ |
(175 |
) |
Net cash (used) provided by
financing activities |
$ |
(8 |
) |
|
$ |
(82 |
) |
|
$ |
(72 |
) |
|
$ |
343 |
|
|
$ |
(289 |
) |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
December 31, |
|
|
|
|
|
|
($ in
millions) |
2024 |
|
2023 |
|
|
|
|
|
|
Selected Balance Sheet
Data: |
|
|
|
|
|
|
|
|
|
Total current assets |
$ |
1,024 |
|
|
$ |
929 |
|
|
|
|
|
|
|
Property, plant and equipment,
net |
$ |
5,680 |
|
|
$ |
2,770 |
|
|
|
|
|
|
|
Deferred tax asset |
$ |
73 |
|
|
$ |
132 |
|
|
|
|
|
|
|
Total current liabilities |
$ |
980 |
|
|
$ |
616 |
|
|
|
|
|
|
|
Long-term debt, net |
$ |
1,132 |
|
|
$ |
540 |
|
|
|
|
|
|
|
Noncurrent asset retirement
obligations |
$ |
995 |
|
|
$ |
422 |
|
|
|
|
|
|
|
Deferred tax liability |
$ |
113 |
|
|
$ |
— |
|
|
|
|
|
|
|
Total stockholders'
equity |
$ |
3,538 |
|
|
$ |
2,219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAINS AND LOSSES FROM COMMODITY DERIVATIVES |
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($
millions) |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
Non-cash derivative (loss) gain |
$ |
(51 |
) |
|
$ |
373 |
|
|
$ |
160 |
|
|
$ |
274 |
|
|
$ |
252 |
|
Net received (paid) on settled commodity derivatives |
|
2 |
|
|
|
(17 |
) |
|
|
(49 |
) |
|
|
(33 |
) |
|
|
(272 |
) |
Net (loss) gain from commodity derivatives |
$ |
(49 |
) |
|
$ |
356 |
|
|
$ |
111 |
|
|
$ |
241 |
|
|
$ |
(20 |
) |
|
|
|
|
|
|
|
|
|
|
CAPITAL INVESTMENTS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($
millions) |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
Facilities (1) |
$ |
44 |
|
$ |
36 |
|
$ |
20 |
|
$ |
111 |
|
$ |
47 |
Drilling and completions |
|
17 |
|
|
19 |
|
|
16 |
|
|
69 |
|
|
67 |
Workovers |
|
17 |
|
|
19 |
|
|
11 |
|
|
54 |
|
|
39 |
Total Oil and natural gas
capital |
|
78 |
|
|
74 |
|
|
47 |
|
|
234 |
|
|
153 |
CMB (1) |
|
6 |
|
|
4 |
|
|
4 |
|
|
12 |
|
|
5 |
Corporate and other |
|
4 |
|
|
1 |
|
|
15 |
|
|
9 |
|
|
27 |
Total capital program |
$ |
88 |
|
$ |
79 |
|
$ |
66 |
|
$ |
255 |
|
$ |
185 |
|
|
|
|
|
|
|
|
|
|
(1) Facilities capital includes $1 million in the fourth quarter of
2023, and $4 million for the total year 2023, to build replacement
water injection facilities which will allow CRC to divert produced
water away from a depleted oil and natural gas reservoir held by
the Carbon TerraVault JV. Construction of these facilities supports
the advancement of CRC’s carbon management business. |
|
|
|
|
|
|
Attachment 2 |
CRC GUIDANCE |
Consolidated1Q25E |
|
Oil and Natural Gas 1Q25E |
|
Carbon Management1Q25E |
Net Production (MBoe/d) |
138 - 142 |
|
|
|
|
Net Oil Production (%) |
~79% |
|
|
|
|
Operating Costs and CMB Expenses ($ millions) |
$335 - $365 |
|
$320 - $340 |
|
$15 - $25 |
Non-Energy Operating and Gas Processing Costs ($ millions) |
|
|
$210 - $225 |
|
|
General and Administrative Expenses ($ millions) |
$80 - $84 |
|
$10 - $12 |
|
$2 - $4 |
Adjusted General and Administrative Expenses ($ millions) |
$75 - $80 |
|
$10 - $12 |
|
$2 - $4 |
Depreciation, Depletion and Amortization ($ millions) |
$125 - $130 |
|
$117 - $121 |
|
|
Capital ($ millions) |
$60 - $70 |
|
$51 - $55 |
|
$5 - $10 |
Drilling, completions and workovers ($ millions) |
$33 - $35 |
|
$33 - $35 |
|
|
Facilities ($ millions) |
$18 - $20 |
|
$18 - $20 |
|
|
Carbon management business ($ millions) |
$5 - $10 |
|
|
|
$5 - $10 |
Corporate and other ($ millions) |
$4 - $5 |
|
|
|
|
Adjusted EBITDAX ($ millions) |
$275 - $295 |
|
$295 - $319 |
|
($20) - ($24) |
|
|
|
|
|
|
Margin from Purchased Commodities ($ millions) (1) |
$10 - $15 |
|
|
|
|
Electricity Margin ($ millions) (2) |
$0 - $5 |
|
|
|
|
Other Operating Revenue and Expenses, net ($ millions)(3) |
($5) - $5 |
|
|
|
|
Transportation Costs ($ millions) |
$18 - $22 |
|
$5 - $10 |
|
|
Taxes Other Than on Income ($ millions) |
$70 - $78 |
|
$57 - $61 |
|
|
Interest and Debt Expense ($ millions) |
$26 - $30 |
|
|
|
|
|
|
|
|
|
|
Other Assumptions: |
|
|
|
|
|
Brent ($/Bbl) |
$76.54 |
|
|
|
|
NYMEX ($/Mcf) |
$3.38 |
|
|
|
|
Oil - % of Brent: |
94% to 98% |
|
|
|
|
NGL - % of Brent: |
65% to 69% |
|
|
|
|
Natural Gas - % of NYMEX: |
110% to 115% |
|
|
|
|
Deferred Income Taxes |
38% - 42% |
|
|
|
|
Effective Tax Rate |
29% |
|
|
|
|
|
|
|
|
|
|
CRC GUIDANCE |
Consolidated2025E |
|
Oil and Natural Gas
2025E |
Carbon Management2025E |
Net Production (MBoe/d) |
132 - 138 |
|
|
|
Net Oil Production (%) |
~79% |
|
|
|
Operating Costs and CMB Expenses ($ millions) |
$1,325 - $1,425 |
|
$1,265 - $1,335 |
$60 - $90 |
Non-Energy Operating and Gas Processing Costs ($ millions) |
|
|
$825 - $855 |
|
General and Administrative Expenses ($ millions) |
$325 - $345 |
|
$40 - $45 |
$10 - $15 |
Adjusted General and Administrative Expenses ($ millions) |
$300 - $320 |
|
$40 - $45 |
$10 - $15 |
Depreciation, Depletion and Amortization ($ millions) |
$490 - $530 |
|
$465 - $480 |
|
Capital ($ millions) |
$285 - $335 |
|
$250 - $280 |
$20 - $30 |
Drilling, completions and workovers ($ millions) |
$165 - $180 |
|
$165 - $180 |
|
Facilities ($ millions) |
$85 - $100 |
|
$85 - $100 |
|
Carbon management business ($ millions) |
$20 - $30 |
|
|
$20 - $30 |
Corporate and other ($ millions) |
$15 - $25 |
|
|
|
Adjusted EBITDAX ($ millions) |
$1,100 - $1,200 |
|
$1,187 - $1,296 |
($87) - ($96) |
|
|
|
|
|
Margin from Purchased Commodities ($ millions) (1) |
$80 - $95 |
|
|
|
Electricity Margin ($ millions) (2) |
$120 - $145 |
|
|
|
Other Operating Revenue and Expenses, net ($ millions) (3) |
($15) - $10 |
|
|
|
Transportation Costs ($ millions) |
$85 - $92 |
|
$25 - $30 |
|
Taxes Other Than on Income ($ millions) |
$275 - $300 |
|
$225 - $235 |
|
Interest and Debt Expense ($ millions) |
$100 - $113 |
|
|
|
|
|
|
|
|
Commodity Assumptions: |
|
|
|
|
Brent ($/Bbl) |
$73.05 |
|
|
|
NYMEX ($/Mcf) |
$3.49 |
|
|
|
Oil - % of Brent: |
94% to 98% |
|
|
|
NGL - % of Brent: |
60% to 68% |
|
|
|
Natural Gas - % of NYMEX: |
95% to 105% |
|
|
|
|
|
|
|
|
Deferred Income Taxes |
35% - 45% |
|
|
|
Effective Tax Rate |
29% |
|
|
|
|
|
|
|
|
(1) Margin from purchased commodities is calculated as the
difference between revenue from marketing of purchased commodities
and costs related to marketing of purchased commodities, and
excludes costs of transportation.(2) Electricity margin is
calculated as the difference between electricity sales and
electricity generation expenses.(3) Other operating revenue and
expenses, net is calculated as the difference between other revenue
and other operating expenses, net and includes exploration expense.
See Attachment 3 for management’s disclosure of its use of these
non-GAAP measures and how these measures provide useful information
to investors about CRC’s results of operations and financial
condition. |
|
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES
RECONCILIATION |
|
|
|
1Q25E |
|
Consolidated |
|
Oil and Natural Gas |
|
Carbon Management |
($ millions) |
Low |
|
High |
|
Low |
|
High |
|
Low |
|
High |
General and administrative expenses |
$ |
80 |
|
|
$ |
84 |
|
|
$ |
10 |
|
$ |
12 |
|
$ |
2 |
|
|
$ |
4 |
|
Equity-settled
stock-based compensation |
|
(4 |
) |
|
|
(4 |
) |
|
|
— |
|
|
— |
|
|
(1 |
) |
|
|
(1 |
) |
Other |
|
(1 |
) |
|
|
— |
|
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Estimated
adjusted general and administrative expenses |
$ |
75 |
|
|
$ |
80 |
|
|
$ |
10 |
|
$ |
12 |
|
$ |
1 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Year 2025E |
|
Consolidated |
|
Oil and Natural Gas |
|
Carbon Management |
($ millions) |
Low |
|
High |
|
Low |
|
High |
|
Low |
|
High |
General and
administrative expenses |
$ |
325 |
|
|
$ |
345 |
|
|
$ |
40 |
|
$ |
45 |
|
$ |
10 |
|
|
$ |
15 |
|
Equity-settled
stock-based compensation |
|
(23 |
) |
|
|
(23 |
) |
|
|
— |
|
|
— |
|
|
(5 |
) |
|
|
(5 |
) |
Other |
|
(2 |
) |
|
|
(2 |
) |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Estimated
adjusted general and administrative expenses |
$ |
300 |
|
|
$ |
320 |
|
|
$ |
40 |
|
$ |
45 |
|
$ |
5 |
|
|
$ |
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
ESTIMATED ADJUSTED EBITDAX RECONCILIATION |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
1Q25E |
|
2025E |
($ millions) |
Low |
|
High |
|
Low |
|
High |
Net income |
$ |
77 |
|
|
$ |
92 |
|
|
$ |
278 |
|
$ |
292 |
Interest and debt expense, net |
|
26 |
|
|
|
30 |
|
|
|
100 |
|
|
113 |
Depreciation, depletion and amortization |
|
125 |
|
|
|
130 |
|
|
|
480 |
|
|
520 |
Income taxes |
|
27 |
|
|
|
30 |
|
|
|
86 |
|
|
96 |
Unusual, infrequent and other items |
|
(14 |
) |
|
|
(22 |
) |
|
|
13 |
|
|
32 |
Other non-cash items |
|
|
|
|
|
|
|
Accretion expense |
|
30 |
|
|
|
31 |
|
|
|
120 |
|
|
124 |
Stock-settled compensation |
|
4 |
|
|
|
4 |
|
|
|
23 |
|
|
23 |
Estimated adjusted
EBITDAX |
$ |
275 |
|
|
$ |
295 |
|
|
$ |
1,100 |
|
$ |
1,200 |
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
115 |
|
|
$ |
130 |
|
|
$ |
752 |
|
$ |
772 |
Cash interest |
|
8 |
|
|
|
14 |
|
|
|
94 |
|
|
100 |
Cash income taxes |
|
— |
|
|
|
— |
|
|
|
66 |
|
|
76 |
Working capital changes |
|
152 |
|
|
|
151 |
|
|
|
188 |
|
|
252 |
Estimated adjusted
EBITDAX |
$ |
275 |
|
|
$ |
295 |
|
|
$ |
1,100 |
|
$ |
1,200 |
|
Oil and Natural Gas |
|
1Q25E |
|
2025E |
($ millions) |
Low |
|
High |
|
Low |
|
High |
Segment profit |
$ |
246 |
|
|
$ |
265 |
|
|
$ |
795 |
|
|
$ |
815 |
|
Depreciation, depletion and amortization |
|
117 |
|
|
|
121 |
|
|
|
460 |
|
|
|
475 |
|
Unusual, infrequent and other items |
|
(96 |
) |
|
|
(100 |
) |
|
|
(183 |
) |
|
|
(119 |
) |
Other non-cash items |
|
|
|
|
|
|
|
Accretion expense |
|
29 |
|
|
|
33 |
|
|
|
115 |
|
|
|
125 |
|
Estimated adjusted
EBITDAX |
$ |
295 |
|
|
$ |
319 |
|
|
$ |
1,187 |
|
|
$ |
1,296 |
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
340 |
|
|
$ |
365 |
|
|
$ |
1,247 |
|
|
$ |
1,267 |
|
Working capital changes |
|
(45 |
) |
|
|
(46 |
) |
|
|
(60 |
) |
|
|
29 |
|
Estimated adjusted
EBITDAX |
$ |
295 |
|
|
$ |
319 |
|
|
$ |
1,187 |
|
|
$ |
1,296 |
|
|
Carbon Management |
|
1Q25E |
|
2025E |
($ millions) |
Low |
|
High |
|
Low |
|
High |
Segment loss |
$ |
(25 |
) |
|
$ |
(30 |
) |
|
$ |
(103 |
) |
|
$ |
(113 |
) |
Interest and debt expense, net |
|
3 |
|
|
|
4 |
|
|
|
11 |
|
|
|
12 |
|
Other non-cash items |
|
|
|
|
|
|
|
Stock-settled compensation |
|
2 |
|
|
|
2 |
|
|
|
5 |
|
|
|
5 |
|
Estimated adjusted
EBITDAX |
$ |
(20 |
) |
|
$ |
(24 |
) |
|
$ |
(87 |
) |
|
$ |
(96 |
) |
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
(21 |
) |
|
$ |
(26 |
) |
|
$ |
(92 |
) |
|
$ |
(102 |
) |
Working capital changes |
|
1 |
|
|
|
2 |
|
|
|
5 |
|
|
|
6 |
|
Estimated adjusted
EBITDAX |
$ |
(20 |
) |
|
$ |
(24 |
) |
|
$ |
(87 |
) |
|
$ |
(96 |
) |
|
Attachment 3 |
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 for the oil and natural gas segment,
adjusted EBITDAX for the carbon management business, net cash
provided by operating activities before changes in operating assets
and liabilities, net, free cash flow, adjusted general and
administrative expenses, and operating costs per BOE. These
measures are also widely used by the industry, the investment
community and CRC’s 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
CRC’s financial performance, such as CRC’s cost of capital and tax
structure, as well as the effect of acquisition and development
costs of CRC’s assets. Management believes that the non-GAAP
measures presented, when viewed in combination with CRC’s 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 earnings 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. CRC defines 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 CRC’s 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 and adjusted net income
per share. |
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($
millions, except per share amounts) |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Net income |
$ |
33 |
|
|
$ |
345 |
|
|
$ |
188 |
|
|
$ |
376 |
|
|
$ |
564 |
|
Unusual, infrequent and other
items: |
|
|
|
|
|
|
|
|
|
Non-cash derivative loss (gain) |
|
51 |
|
|
|
(373 |
) |
|
|
(160 |
) |
|
|
(274 |
) |
|
|
(252 |
) |
Asset impairment |
|
1 |
|
|
|
— |
|
|
|
— |
|
|
|
14 |
|
|
|
3 |
|
Severance and termination costs |
|
2 |
|
|
|
27 |
|
|
|
— |
|
|
|
30 |
|
|
|
10 |
|
Aera merger related costs |
|
1 |
|
|
|
30 |
|
|
|
— |
|
|
|
57 |
|
|
|
— |
|
Increased power and fuel costs due to power plant maintenance |
|
6 |
|
|
|
8 |
|
|
|
— |
|
|
|
50 |
|
|
|
— |
|
Net gain on asset divestitures |
|
(4 |
) |
|
|
— |
|
|
|
(25 |
) |
|
|
(11 |
) |
|
|
(32 |
) |
Loss on early extinguishment of debt |
|
— |
|
|
|
5 |
|
|
|
1 |
|
|
|
5 |
|
|
|
1 |
|
Other, net |
|
13 |
|
|
|
6 |
|
|
|
16 |
|
|
|
38 |
|
|
|
46 |
|
Total unusual, infrequent and other items |
|
70 |
|
|
|
(297 |
) |
|
|
(168 |
) |
|
|
(91 |
) |
|
|
(224 |
) |
Income tax (benefit) provision of adjustments at effective tax
rate |
|
(19 |
) |
|
|
89 |
|
|
|
47 |
|
|
|
32 |
|
|
|
63 |
|
Income tax benefit - out of period |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(31 |
) |
Adjusted net income |
$ |
84 |
|
|
$ |
137 |
|
|
$ |
67 |
|
|
$ |
317 |
|
|
$ |
372 |
|
|
|
|
|
|
|
|
|
|
|
Net income per share -
basic |
$ |
0.36 |
|
|
$ |
3.86 |
|
|
$ |
2.74 |
|
|
$ |
4.74 |
|
|
$ |
8.10 |
|
Net income per share -
diluted |
$ |
0.36 |
|
|
$ |
3.78 |
|
|
$ |
2.60 |
|
|
$ |
4.62 |
|
|
$ |
7.78 |
|
Adjusted net income per share
- basic |
$ |
0.93 |
|
|
$ |
1.53 |
|
|
$ |
0.98 |
|
|
$ |
4.00 |
|
|
$ |
5.34 |
|
Adjusted net income per share
- diluted |
$ |
0.91 |
|
|
$ |
1.50 |
|
|
$ |
0.93 |
|
|
$ |
3.89 |
|
|
$ |
5.13 |
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED EBITDAX |
|
|
|
|
|
|
|
CRC defines 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. CRC believes this measure provides useful
information in assessing its financial condition, results of
operations and cash flows and is widely used by the industry, the
investment community and its 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
CRC’s financial performance, such as its cost of capital and tax
structure, as well as depreciation, depletion and amortization of
CRC's assets. This measure should be read in conjunction with the
information contained in CRC’s financial statements prepared in
accordance with GAAP. A version of adjusted EBITDAX is a material
component of certain of its financial covenants under CRC’s
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. CRC has supplemented its non-GAAP
measures of consolidated adjusted EBITDAX with adjusted EBITDAX for
its oil and gas segment (E&P adjusted EBITDAX) and its carbon
management segment (CMB adjusted EBITDAX). Management believes
these supplemental measures are useful for investors to understand
the results of the core oil and gas business and its investment in
developing the carbon management business. |
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($ millions, except per BOE amounts) |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Net income |
$ |
33 |
|
|
$ |
345 |
|
|
$ |
188 |
|
|
$ |
376 |
|
|
$ |
564 |
|
Interest and debt expense |
|
28 |
|
|
|
29 |
|
|
|
13 |
|
|
|
87 |
|
|
|
56 |
|
Depreciation, depletion and amortization |
|
142 |
|
|
|
140 |
|
|
|
55 |
|
|
|
388 |
|
|
|
225 |
|
Income tax provision |
|
8 |
|
|
|
138 |
|
|
|
79 |
|
|
|
140 |
|
|
|
184 |
|
Exploration expense |
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
Interest income |
|
(4 |
) |
|
|
(1 |
) |
|
|
(7 |
) |
|
|
(19 |
) |
|
|
(21 |
) |
Unusual, infrequent and other items (1) |
|
70 |
|
|
|
(297 |
) |
|
|
(168 |
) |
|
|
(91 |
) |
|
|
(224 |
) |
Non-cash items |
|
|
|
|
|
|
|
|
|
Accretion expense |
|
31 |
|
|
|
31 |
|
|
|
11 |
|
|
|
87 |
|
|
|
46 |
|
Stock-based compensation |
|
6 |
|
|
|
6 |
|
|
|
6 |
|
|
|
23 |
|
|
|
27 |
|
Taxes related to acquisition accounting |
|
2 |
|
|
|
10 |
|
|
|
— |
|
|
|
12 |
|
|
|
— |
|
Pension and post-retirement benefits |
|
— |
|
|
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
Adjusted
EBITDAX |
$ |
316 |
|
|
$ |
402 |
|
|
$ |
179 |
|
|
$ |
1,006 |
|
|
$ |
862 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
206 |
|
|
$ |
220 |
|
|
$ |
131 |
|
|
$ |
610 |
|
|
$ |
653 |
|
Cash interest payments |
|
42 |
|
|
|
24 |
|
|
|
1 |
|
|
|
88 |
|
|
|
49 |
|
Cash interest received |
|
(4 |
) |
|
|
(1 |
) |
|
|
(7 |
) |
|
|
(19 |
) |
|
|
(21 |
) |
Cash income taxes |
|
50 |
|
|
|
29 |
|
|
|
41 |
|
|
|
105 |
|
|
|
121 |
|
Exploration expenditures |
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
Adjustments to working capital changes |
|
22 |
|
|
|
129 |
|
|
|
12 |
|
|
|
220 |
|
|
|
57 |
|
Adjusted
EBITDAX |
$ |
316 |
|
|
$ |
402 |
|
|
$ |
179 |
|
|
$ |
1,006 |
|
|
$ |
862 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX per
Boe |
$ |
24.35 |
|
|
$ |
30.19 |
|
|
$ |
23.57 |
|
|
$ |
25.09 |
|
|
$ |
27.51 |
|
|
|
|
|
|
|
|
|
|
|
(1) See Adjusted
Net Income (Loss) reconciliation. |
|
|
|
|
|
|
|
|
|
|
|
|
|
SEGMENT ADJUSTED EBITDAX |
|
|
|
|
|
|
|
CRC defines segments 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. CRC believes this segment measure
provides useful information in assessing the financial results of
each segment. Although this is a non-GAAP measure, the amounts
included in the calculation were computed in accordance with GAAP.
This measure should be read in conjunction with Note 16 Segment
Information in CRC’s 2024 Annual Report. |
|
|
|
|
Oil & Natural Gas
Segment |
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($
millions, except per BOE amounts) |
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Segment profit |
$ |
273 |
|
|
$ |
305 |
|
|
$ |
223 |
|
|
$ |
815 |
|
|
$ |
922 |
|
Depreciation, depletion and amortization |
|
125 |
|
|
|
126 |
|
|
|
46 |
|
|
|
354 |
|
|
|
205 |
|
Exploration expense |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2 |
|
|
|
3 |
|
Accretion expense |
|
31 |
|
|
|
31 |
|
|
|
11 |
|
|
|
87 |
|
|
|
46 |
|
Adjusted income items |
|
(3 |
) |
|
|
15 |
|
|
|
(22 |
) |
|
|
54 |
|
|
|
(30 |
) |
Adjusted EBITDAX - Oil
and Natural Gas |
$ |
426 |
|
|
$ |
477 |
|
|
$ |
258 |
|
|
$ |
1,312 |
|
|
$ |
1,146 |
|
|
|
|
|
|
|
|
|
|
|
Carbon Management
Segment |
|
|
|
|
|
|
|
|
|
Segment loss |
$ |
(30 |
) |
|
$ |
(25 |
) |
|
$ |
(22 |
) |
|
$ |
(94 |
) |
|
$ |
(66 |
) |
Interest on contingent liability (related to Carbon TerraVault
JV) |
|
3 |
|
|
|
3 |
|
|
|
1 |
|
|
|
9 |
|
|
|
5 |
|
Loss from investment in unconsolidated subsidiaries |
|
1 |
|
|
|
3 |
|
|
|
— |
|
|
|
5 |
|
|
|
— |
|
Adjusted EBITDAX -
Carbon Management |
$ |
(26 |
) |
|
$ |
(19 |
) |
|
$ |
(21 |
) |
|
$ |
(80 |
) |
|
$ |
(61 |
) |
|
|
|
|
|
|
|
|
|
|
FREE CASH FLOW |
|
|
|
|
|
|
|
|
|
|
|
Management uses free cash flow, which is defined by CRC as net cash
provided by operating activities less capital investments, as a
measure of liquidity. The following table presents a reconciliation
of CRC’s net cash provided by operating activities to free cash
flow. CRC supplemented its non-GAAP measure of free cash flow with
net cash provided by operating activities before changes in
operating assets and liabilities, net, which it believes is a
useful measure for investors to understand the predictability of
CRC’s cash flow by removing fluctuations related to the timing of
payments between periods. CRC defines adjusted free cash flow after
special items as free cash flow before transaction and integration
costs from the Aera Merger. |
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($
millions) |
|
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities before changes in
operating assets and liabilities, net |
|
$ |
258 |
|
|
$ |
249 |
|
|
$ |
104 |
|
|
$ |
707 |
|
|
$ |
647 |
|
Changes in operating assets
and liabilities, net |
|
|
(52 |
) |
|
|
(29 |
) |
|
|
27 |
|
|
|
(97 |
) |
|
|
6 |
|
Net cash provided by operating
activities |
|
|
206 |
|
|
|
220 |
|
|
|
131 |
|
|
|
610 |
|
|
|
653 |
|
Capital investments |
|
|
(88 |
) |
|
|
(79 |
) |
|
|
(66 |
) |
|
|
(255 |
) |
|
|
(185 |
) |
Free cash flow |
|
$ |
118 |
|
|
$ |
141 |
|
|
$ |
65 |
|
|
$ |
355 |
|
|
$ |
468 |
|
Add: Aera merger related
costs |
|
|
1 |
|
|
|
30 |
|
|
|
— |
|
|
|
57 |
|
|
|
— |
|
Free cash flow after
special items |
|
$ |
119 |
|
|
$ |
171 |
|
|
$ |
65 |
|
|
$ |
412 |
|
|
$ |
468 |
|
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED GENERAL & ADMINISTRATIVE
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
Management uses a measure called adjusted general and
administrative (G&A) expenses and adjusted G&A per BOE to
provide useful information to investors interested in comparing
CRC’s costs between periods and performance to its peers. |
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($
millions) |
|
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
General and administrative expenses |
|
$ |
95 |
|
|
$ |
106 |
|
|
$ |
66 |
|
|
$ |
321 |
|
|
$ |
267 |
|
Stock-based compensation |
|
|
(6 |
) |
|
|
(6 |
) |
|
|
(6 |
) |
|
|
(23 |
) |
|
|
(27 |
) |
Information technology
infrastructure |
|
|
— |
|
|
|
— |
|
|
|
(4 |
) |
|
|
(3 |
) |
|
|
(17 |
) |
Accelerated vesting |
|
|
(3 |
) |
|
|
(9 |
) |
|
|
— |
|
|
|
(12 |
) |
|
|
— |
|
Retention awards |
|
|
— |
|
|
|
(2 |
) |
|
|
— |
|
|
|
(2 |
) |
|
|
— |
|
Other |
|
|
(1 |
) |
|
|
— |
|
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(5 |
) |
Adjusted G&A expenses |
|
$ |
85 |
|
|
$ |
89 |
|
|
$ |
55 |
|
|
$ |
279 |
|
|
$ |
218 |
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted G&A per BOE |
|
$ |
6.55 |
|
|
$ |
6.68 |
|
|
$ |
7.24 |
|
|
$ |
6.96 |
|
|
$ |
6.96 |
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
COSTS PER BOE, EXCLUDING EFFECTS OF PSCs |
|
|
|
|
|
|
|
|
|
|
|
The reporting of PSC-type contracts creates a difference between
reported operating costs, which are for the full field, and
reported volumes, which are only CRC’s net share, inflating the per
barrel operating costs. The following table presents operating
costs after adjusting for the excess costs attributable to
PSCs. |
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
($ per
BOE) |
|
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Energy operating costs
(1) |
|
$ |
7.70 |
|
|
$ |
7.29 |
|
|
$ |
8.65 |
|
|
$ |
7.38 |
|
|
$ |
10.31 |
|
Gas processing costs (2) |
|
|
0.31 |
|
|
|
0.38 |
|
|
|
0.60 |
|
|
|
0.40 |
|
|
|
0.58 |
|
Non-energy operating
costs(3) |
|
|
17.34 |
|
|
|
16.06 |
|
|
|
15.24 |
|
|
|
16.73 |
|
|
|
15.35 |
|
Operating costs |
|
$ |
25.35 |
|
|
$ |
23.73 |
|
|
$ |
24.49 |
|
|
$ |
24.51 |
|
|
$ |
26.24 |
|
|
|
|
|
|
|
|
|
|
|
|
Costs attributable to
PSCs |
|
|
|
|
|
|
|
|
|
|
Excess energy operating costs attributable to PSCs |
|
$ |
(0.46 |
) |
|
$ |
(0.75 |
) |
|
$ |
(1.01 |
) |
|
$ |
(0.64 |
) |
|
$ |
(1.00 |
) |
Excess non-energy operating costs attributable to PSCs |
|
|
(0.76 |
) |
|
|
(0.48 |
) |
|
|
(1.32 |
) |
|
|
(1.03 |
) |
|
|
(1.25 |
) |
Excess costs attributable to PSCs |
|
$ |
(1.22 |
) |
|
$ |
(1.23 |
) |
|
$ |
(2.33 |
) |
|
$ |
(1.67 |
) |
|
$ |
(2.25 |
) |
|
|
|
|
|
|
|
|
|
|
|
Energy operating costs, excluding effect of PSCs (1) |
|
$ |
7.24 |
|
|
$ |
6.54 |
|
|
$ |
7.64 |
|
|
$ |
6.74 |
|
|
$ |
9.31 |
|
Gas processing costs, excluding effect of PSCs (2) |
|
|
0.31 |
|
|
|
0.38 |
|
|
|
0.60 |
|
|
|
0.40 |
|
|
|
0.58 |
|
Non-energy operating costs, excluding effect of PSCs (3) |
|
|
16.58 |
|
|
|
15.58 |
|
|
|
13.92 |
|
|
|
15.70 |
|
|
|
14.10 |
|
Operating costs,
excluding effects of PSCs |
|
$ |
24.13 |
|
|
$ |
22.50 |
|
|
$ |
22.16 |
|
|
$ |
22.84 |
|
|
$ |
23.99 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Energy operating costs consist of purchased natural gas used to
generate electricity for operations and steamfloods, purchased
electricity and internal costs to generate electricity used in
CRC’s operations. |
(2) Gas processing costs include costs associated with compression,
maintenance and other activities needed to run CRC’s gas processing
facilities at Elk Hills. |
(3) Non-energy operating costs equal total operating costs less
energy operating costs and gas processing costs. |
|
PV-10 AND STANDARDIZED MEASURE |
|
|
|
The following table presents a reconciliation of the standardized
measure of discounted future net cash flows (Standardized Measure)
to the non-GAAP financial measure of PV-10 of cash flows: |
|
|
|
($ millions) |
|
As of December 31, 2024 |
Standardized Measure |
|
$ |
6,702 |
Present value of future income
taxes discounted at 10% |
|
|
2,175 |
PV-10 of cash flows (*) |
|
$ |
8,877 |
|
|
|
(*) PV-10 is a non-GAAP financial measure and represents the
year-end present value of estimated future cash inflows from proved
oil and natural gas reserves, less future development and operating
costs, discounted at 10% per annum to reflect the timing of future
cash flows and using SEC prescribed pricing assumptions for the
period. PV-10 differs from Standardized Measure because
Standardized Measure includes the effects of future income taxes on
future net cash flows. Neither PV-10 nor Standardized Measure
should be construed as the fair value of oil and natural gas
reserves. Standardized Measure is prescribed by the SEC as an
industry standard asset value measure to compare reserves with
consistent pricing costs and discount assumptions. PV-10
facilitates the comparisons to other companies as it is not
dependent on the tax-paying status of the entity. |
Attachment 4 |
PRODUCTION STATISTICS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
Net Production Per
Day |
|
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Oil (MBbl/d) |
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin |
|
86 |
|
90 |
|
32 |
|
58 |
|
33 |
Los Angeles Basin |
|
17 |
|
17 |
|
18 |
|
17 |
|
19 |
Other Basins |
|
9 |
|
6 |
|
— |
|
5 |
|
— |
Total |
|
112 |
|
113 |
|
50 |
|
80 |
|
52 |
|
|
|
|
|
|
|
|
|
|
|
NGLs
(MBbl/d) |
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin |
|
10 |
|
11 |
|
11 |
|
10 |
|
11 |
Total |
|
10 |
|
11 |
|
11 |
|
10 |
|
11 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(MMcf/d) |
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin |
|
98 |
|
111 |
|
114 |
|
99 |
|
119 |
Los Angeles Basin |
|
1 |
|
1 |
|
1 |
|
1 |
|
1 |
Sacramento Basin |
|
13 |
|
13 |
|
15 |
|
13 |
|
15 |
Other Basins |
|
3 |
|
1 |
|
— |
|
4 |
|
— |
Total |
|
115 |
|
126 |
|
130 |
|
117 |
|
135 |
|
|
|
|
|
|
|
|
|
|
|
Total Net Production
(MBoe/d) |
|
141 |
|
145 |
|
83 |
|
110 |
|
86 |
|
|
|
|
|
|
|
|
|
|
|
Gross Operated and Net Non-Operated |
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
Production Per
Day |
|
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Oil (MBbl/d) |
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin |
|
93 |
|
96 |
|
36 |
|
63 |
|
37 |
Los Angeles Basin |
|
23 |
|
23 |
|
25 |
|
23 |
|
25 |
Other Basins |
|
11 |
|
8 |
|
— |
|
6 |
|
— |
Total |
|
127 |
|
127 |
|
61 |
|
92 |
|
62 |
|
|
|
|
|
|
|
|
|
|
|
NGLs
(MBbl/d) |
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin |
|
10 |
|
11 |
|
11 |
|
11 |
|
12 |
Other Basins |
|
1 |
|
— |
|
— |
|
— |
|
— |
Total |
|
11 |
|
11 |
|
11 |
|
11 |
|
12 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(MMcf/d) |
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin |
|
135 |
|
137 |
|
129 |
|
131 |
|
135 |
Los Angeles Basin |
|
6 |
|
7 |
|
8 |
|
7 |
|
7 |
Sacramento Basin |
|
17 |
|
16 |
|
18 |
|
17 |
|
19 |
Other Basins |
|
3 |
|
3 |
|
— |
|
2 |
|
— |
Total |
|
161 |
|
163 |
|
155 |
|
157 |
|
161 |
Total Gross Production
(MBoe/d) |
|
165 |
|
165 |
|
98 |
|
129 |
|
101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 5 |
PRICE
STATISTICS |
|
|
|
|
|
|
|
|
|
|
4th Quarter |
|
3rd Quarter |
|
4th Quarter |
|
Total Year |
|
Total Year |
|
2024 |
|
2024 |
|
2023 |
|
2024 |
|
2023 |
Oil ($ per
Bbl) |
|
|
|
|
|
|
|
|
|
Realized price with derivative settlements |
$ |
73.00 |
|
|
$ |
75.38 |
|
|
$ |
71.34 |
|
|
$ |
75.66 |
|
|
$ |
65.97 |
|
Realized price without
derivative settlements |
$ |
72.82 |
|
|
$ |
77.10 |
|
|
$ |
82.00 |
|
|
$ |
76.92 |
|
|
$ |
80.41 |
|
NGLs ($/Bbl) |
$ |
52.62 |
|
|
$ |
45.77 |
|
|
$ |
49.08 |
|
|
$ |
48.93 |
|
|
$ |
48.94 |
|
Natural gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
Realized price with derivative
settlements |
$ |
3.65 |
|
|
$ |
2.68 |
|
|
$ |
4.66 |
|
|
$ |
2.99 |
|
|
$ |
8.59 |
|
Realized price without
derivative settlements |
$ |
3.65 |
|
|
$ |
2.68 |
|
|
$ |
4.66 |
|
|
$ |
2.99 |
|
|
$ |
8.59 |
|
|
|
|
|
|
|
|
|
|
|
Index
Prices |
|
|
|
|
|
|
|
|
|
Brent oil ($/Bbl) |
$ |
73.97 |
|
|
$ |
78.54 |
|
|
$ |
82.69 |
|
|
$ |
79.84 |
|
|
$ |
82.22 |
|
WTI oil ($/Bbl) |
$ |
70.27 |
|
|
$ |
75.09 |
|
|
$ |
78.32 |
|
|
$ |
75.72 |
|
|
$ |
77.62 |
|
NYMEX average monthly settled
price ($/MMBtu) |
$ |
2.79 |
|
|
$ |
2.16 |
|
|
$ |
2.88 |
|
|
$ |
2.27 |
|
|
$ |
2.74 |
|
|
|
|
|
|
|
|
|
|
|
Realized Prices as
Percentage of Index Prices |
|
|
|
|
|
|
|
|
|
Oil with derivative
settlements as a percentage of Brent |
|
99 |
% |
|
|
96 |
% |
|
|
86 |
% |
|
|
95 |
% |
|
|
80 |
% |
Oil without derivative
settlements as a percentage of Brent |
|
98 |
% |
|
|
98 |
% |
|
|
99 |
% |
|
|
96 |
% |
|
|
98 |
% |
|
|
|
|
|
|
|
|
|
|
Oil with derivative
settlements as a percentage of WTI |
|
104 |
% |
|
|
100 |
% |
|
|
91 |
% |
|
|
100 |
% |
|
|
85 |
% |
Oil without derivative
settlements as a percentage of WTI |
|
104 |
% |
|
|
103 |
% |
|
|
105 |
% |
|
|
102 |
% |
|
|
104 |
% |
|
|
|
|
|
|
|
|
|
|
NGLs as a percentage of
Brent |
|
71 |
% |
|
|
58 |
% |
|
|
59 |
% |
|
|
61 |
% |
|
|
60 |
% |
NGLs as a percentage of
WTI |
|
75 |
% |
|
|
61 |
% |
|
|
63 |
% |
|
|
65 |
% |
|
|
63 |
% |
|
|
|
|
|
|
|
|
|
|
Natural gas with derivative
settlements as a percentage of NYMEX contract month average |
|
131 |
% |
|
|
124 |
% |
|
|
162 |
% |
|
|
132 |
% |
|
|
314 |
% |
|
|
|
|
|
|
|
|
|
|
Natural gas without derivative
settlements as a percentage of NYMEX contract month average |
|
131 |
% |
|
|
124 |
% |
|
|
162 |
% |
|
|
132 |
% |
|
|
314 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 6 |
FOURTH QUARTER 2024 DRILLING ACTIVITY |
|
San Joaquin |
|
Los Angeles |
|
Ventura |
|
Sacramento |
|
|
Wells Drilled |
Basin |
|
Basin |
|
Basin |
|
Basin |
|
Total |
|
|
|
|
|
|
|
|
|
|
Development
Wells |
|
|
|
|
|
|
|
|
|
Primary |
4 |
|
— |
|
— |
|
— |
|
4 |
Waterflood |
— |
|
— |
|
— |
|
— |
|
— |
Steamflood |
— |
|
— |
|
— |
|
— |
|
— |
Total
(1) |
4 |
|
— |
|
— |
|
— |
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL YEAR 2024
DRILLING ACTIVITY |
|
|
|
|
|
|
|
|
|
|
San Joaquin |
|
Los Angeles |
|
Ventura |
|
Sacramento |
|
|
Wells Drilled |
Basin |
|
Basin |
|
Basin |
|
Basin |
|
Total |
|
|
|
|
|
|
|
|
|
|
Development
Wells |
|
|
|
|
|
|
|
|
|
Primary |
10 |
|
— |
|
— |
|
— |
|
10 |
Waterflood |
— |
|
— |
|
— |
|
— |
|
— |
Steamflood |
— |
|
— |
|
— |
|
— |
|
— |
Total
(1) |
10 |
|
— |
|
— |
|
— |
|
10 |
|
|
|
|
|
|
|
|
|
|
(1) Includes steam injectors and drilled but uncompleted wells,
which are not included in the SEC definition of wells drilled. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 7 |
OIL
HEDGES AS OF DECEMBER 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2025 |
|
Q2 2025 |
|
Q3 2025 |
|
Q4 2025 |
|
2026 |
|
2027 |
|
2028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold
Calls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day |
|
|
30,000 |
|
|
30,000 |
|
|
30,000 |
|
|
29,000 |
|
|
15,000 |
|
|
— |
|
|
— |
Weighted-average Brent price per barrel |
|
$ |
87.08 |
|
$ |
87.08 |
|
$ |
87.08 |
|
$ |
87.13 |
|
$ |
85.00 |
|
$ |
— |
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day |
|
|
52,837 |
|
|
46,506 |
|
|
44,126 |
|
|
42,626 |
|
|
30,449 |
|
|
13,882 |
|
|
1,697 |
Weighted-average Brent price per barrel |
|
$ |
72.48 |
|
$ |
71.31 |
|
$ |
70.62 |
|
$ |
69.94 |
|
$ |
67.95 |
|
$ |
65.53 |
|
$ |
65.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Puts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels per day |
|
|
30,000 |
|
|
30,000 |
|
|
30,000 |
|
|
29,000 |
|
|
15,000 |
|
|
— |
|
|
— |
Weighted-average Brent price per barrel |
|
$ |
61.67 |
|
$ |
61.67 |
|
$ |
61.67 |
|
$ |
61.72 |
|
$ |
60.00 |
|
$ |
— |
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 7 |
NATURAL
GAS HEDGES AS OF DECEMBER 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2025 |
|
Q2 2025 |
|
Q3 2025 |
|
Q4 2025 |
|
2026 |
|
2027 |
|
2028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SoCal
Border |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtu per day |
|
|
10,000 |
|
|
29,074 |
|
|
25,750 |
|
|
22,408 |
|
|
660 |
|
|
— |
|
|
— |
Weighted-average price per MMBtu |
|
$ |
6.02 |
|
$ |
3.44 |
|
$ |
3.48 |
|
$ |
3.53 |
|
$ |
6.29 |
|
$ |
— |
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northwest Pipeline
(NWPL) Rockies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtu per day |
|
|
50,999 |
|
|
51,750 |
|
|
51,750 |
|
|
51,750 |
|
|
44,618 |
|
|
12,616 |
|
|
1,576 |
Weighted-average price per MMBtu |
|
$ |
5.48 |
|
$ |
2.95 |
|
$ |
2.95 |
|
$ |
4.22 |
|
$ |
4.01 |
|
$ |
4.34 |
|
$ |
3.95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PG&E
Citygate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtu per day |
|
|
14,000 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
Weighted-average price per MMBtu |
|
$ |
6.10 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
This press release was published by a CLEAR® Verified
individual.
Grafico Azioni California Resources (NYSE:CRC)
Storico
Da Feb 2025 a Mar 2025
Grafico Azioni California Resources (NYSE:CRC)
Storico
Da Mar 2024 a Mar 2025