California Resources Corporation Raises its
Share Repurchase Program by Nearly 30% to $1.1 Billion and
Meaningfully Advances its Carbon Management Business
California Resources Corporation (NYSE: CRC), an independent oil
and natural gas company committed to energy transition in the
sector, today reported fourth quarter and full year 2022
operational and financial results.
"CRC continued to deliver as we closed out 2022 with record
operating cash flow which allowed us to return $372 million to
shareholders. Given our positive outlook on 2023 free cash flow
generation, we are increasing our Share Repurchase Program to $1.1
billion, a $250 million or nearly 30% increase, with approximately
$640 million remaining on our authorization as of December 31, 2022
after taking into account this increase. Our 2023 development plans
will utilize current permits in-hand and focus on workovers and
maintenance opportunities to maximize cash flow per share," said
Mac McFarland, CRC’s President and Chief Executive Officer.
"We continued to build off the momentum we generated throughout
the year. In late 2022 and the start of 2023, our Carbon Management
Business signed two carbon dioxide management agreements (CDMAs) to
sequester 470,000 metric tons (MT) of carbon dioxide (CO2).
Further, we announced the formation of a consortium of
organizations across industry, technology, academia, national labs,
community, government, and labor to create the California Direct
Air Capture (DAC) Hub, reinforcing our dedication and commitment to
California’s energy transition. For the balance of 2023, we will
continue developing our Carbon Management Business, while making
strides in our CalCapture project, filing additional Class VI
permits with the EPA and advancing numerous additional CDMAs."
Annual Highlights
- Reported net income attributable to common stock of $524
million, or $6.75 per diluted share. When adjusted for items
analysts typically exclude from estimates including noncash mark to
market gains and gains on asset divestitures, the Company’s
adjusted net income1 was $384 million, or $4.95 per diluted
share
- Generated operating cash flow of $690 million, adjusted
EBITDAX1 of $852 million, free cash flow1 of $311 million, and
E&P, Corporate and Other Free Cash Flow1 of $362 million in
2022
- Returned $372 million to shareholders in 2022, $59 million in
dividends and $313 million through the Share Repurchase Program,
while maintaining a strong cash balance of $307 million
- Produced an average of 55,000 barrels of oil per day throughout
the year, with total drilling and completions and workover capital
expenditures of $278 million in 2022
- Increased the Share Repurchase Program by $250 million to $1.1
billion, extended the program term through June 30, 2024, and
repurchased ~14% of the Company's common stock since program
inception
- Advanced the Carbon Management Business in California on
several fronts:
- Formed a joint venture with Brookfield Renewables,
- Submitted Class VI permits to EPA for an additional 94 MMT of
CO2 reservoirs,
- Executed two CDMAs to sequester 470,000 MT of CO2 per annum at
CTV I and CTV III reservoirs, and
- Made substantial progress on CalCapture Project with targeted
Final Investment Decision (FID) in early 2024
- Through its subsidiary CTV Direct, formed in February 2023 a
consortium of organizations across industry, technology, academia,
national labs, community, government, and labor that is intended to
create California's first DAC Hub
Fourth Quarter 2022
Highlights
Financial
- Reported net income of $83 million, or $1.11 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 $93 million,
or $1.24 per diluted share
- Generated net cash provided by operating activities of $114
million, adjusted EBITDAX1 of $208 million and free cash flow1 of
$39 million
- Ended the quarter with $307 million of cash on hand and an
undrawn RBL credit facility representing $765 million of total
liquidity2
- Declared a quarterly dividend of $0.2825 per share of common
stock, totaling ~$20 million payable on March 16, 2023 to
shareholders of record on March 6, 2023, with subsequent quarterly
dividends subject to final determination and Board approval
- Repurchased 1,521,190 common shares for $66 million during the
fourth quarter of 2022; repurchased an aggregate 11,456,260 shares
for $461 million since the inception of the Share Repurchase
Program through December 31, 2022
Operations
- Produced an average of 91,000 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 $81 million during the quarter
- Operated one drilling rig in the San Joaquin Basin and two
drilling rigs in the Los Angeles Basin; drilled 23 wells (23 online
in 4Q22)
- Operated 36 maintenance rigs in the fourth quarter
2023 Guidance and Capital
Program3
CRC expects its 2023 capital program to range between $200 and
$245 million. The program includes $154 to $184 million of adjusted
capital for oil and natural gas development4, $15 to $25 million of
adjusted capital for carbon management projects4 and $31 to $36
million for corporate and other activities, including procuring
long-lead time items for planned maintenance at CRC's Elk Hills
power plant in 2024. The foregoing amounts related to carbon
management projects does not include amounts funded by Brookfield
through the Carbon TerraVault JV. See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 8 Investment in
Unconsolidated Subsidiary and Related Party Transactions for more
information on CRC's joint venture with Brookfield. The actual
amount of spending under CRC's 2023 capital program will depend on
a variety of factors including regulatory and permitting
status.
CRC expects to produce between 85,000 and 91,000 Boe/d3 (~60%
oil) in 2023. CRC plans to run a development program averaging 1.5
rigs in 2023 for drilling locations for which we already have
permits and will otherwise focus on workover and maintenance
activity to offset base decline following the ongoing impact of the
Kern County EIR litigation.
On a go-forward basis utilizing a 1.5 rig program, CRC would
expect to spend ~$155 million in E&P drilling and completions
and workover capital. This level of spending excludes one-time
items and CMB capital which is expected to be funded by projected
CTV JV contributions.
CRC GUIDANCE3
Total 2023E
CMB 2023E
E&P, Corp. & Other
2023E
Net Total Production (MBoe/d)
85 - 91
85 - 91
Net Oil Production (MBbl/d)
51 - 55
51 - 55
Operating Costs ($ millions)
$845 - $895
$845 - $895
CMB Expenses5 ($ millions)
$25 - $35
$25 - $35
Adjusted General and Administrative
Expenses1 ($ millions)
$195 - $225
$10 - $15
$185 - $210
Total Capital ($ millions)
$200 - $245
$5 - $15
$195 - $230
Adjusted Total Capital4 ($ millions)
$200 - $245
$15 - $25
$185 - $220
Drilling & Completions
$66 - $76
$66 - $76
Workovers
$44 - $54
$44 - $54
Adjusted Facilities
$44 - $54
$44 - $54
Corporate & Other
$31 - $36
$31 - $36
Adjusted CMB
$15 - $25
$15 - $25
Free Cash Flow1 ($ millions)
$330 - $440
($60) - ($80)
$410 - $500
Natural Gas Trading, Net ($ millions)
$60 - $70
$60 - $70
Net Electricity ($ millions)
$80 - $120
$80 - $120
Transportation Expense ($ millions)
$50 - $70
$50 - $70
ARO Settlement Payments* ($ millions)
$55 - $60
$55 - $60
Taxes Other Than on Income* ($
millions)
$175 - $185
$175 - $185
Interest and Debt Expense* ($
millions)
$55 - $60
$55 - $60
Cash Income Taxes* ($ millions)
$80 - $100
$80 - $100
Commodity Realizations:
Oil - % of Brent:
97% - 99%
97% - 99%
NGL - % of Brent:
58% - 64%
58% - 64%
Natural Gas - % of NYMEX:
150% - 250%
150% - 250%
*Notes:
- 2023E ARO Settlement Payments: ~25% of estimated annual amount
is paid every quarter
- 2023E Taxes Other Than on Income: ~30% of estimated annual
amount is paid in 1Q and 4Q, respectively
- 2023E Interest Expense: ~46% of estimated annual amount is paid
in cash in 1Q and 3Q, respectively
- Cash Income Taxes aren’t paid evenly throughout 2023
First Quarter 2023 Guidance and Capital
Program3
CRC expects its first quarter 2023 capital program to range
between $57 and $69 million assuming normal operating conditions.
This includes $2 to $4 million for carbon management projects.
At this level of spending, CRC expects to produce between 89,000
and 91,000 Boe/d3 (~59% oil) in the first quarter of 2023 and plans
to run 3 drilling rigs in the Long Beach and San Joaquin basins
developing drilling locations for which we already have permits.
CRC will also focus on workover activity throughout 2023 to offset
base decline following the impact of the Kern County EIR
litigation.
CRC sells all of its natural gas not used in its operations into
the California market where the majority of these sales are done
via bid in monthly method. Given the recent natural gas
environment, CRC expects the first quarter of 2023 to benefit on a
net basis, particularly in its natural gas revenue and natural gas
marketing segments. CRC also expects to see higher costs related to
purchased natural gas and energy operating costs, but as CRC is net
long natural gas, the benefit will exceed the higher costs.
CRC GUIDANCE3
Total 1Q23E
CMB 1Q23E
E&P, Corp. & Other
1Q23E
Net Total Production (MBoe/d)
89 - 91
89 - 91
Net Oil Production (MBbl/d)
53 - 54
53 - 54
Operating Costs ($ millions)
$260 - $270
$260 - $270
CMB Expenses5 ($ millions)
$5 - $10
$5 - $10
Adjusted General and Administrative
Expenses1 ($ millions)
$50 - $58
$3 - $5
$47 - $53
Total Capital ($ millions)
$57 - $69
$2 - $4
$55 - $65
Adjusted Total Capital4 ($ millions)
$57 - $69
$2 - $4
$55 - $65
Free Cash Flow1 ($ millions)
$151 - $180
($15) - ($24)
$175 - $195
Natural Gas Trading, Net ($ millions)
$35 - $45
$35 - $45
Net Electricity ($ millions)
$25 - $35
$25 - $35
Transportation Expense ($ millions)
$14 - $16
$14 - $16
Commodity Realizations:
Oil - % of Brent:
97% - 99%
97% - 99%
NGL - % of Brent:
63% - 65%
63% - 65%
Natural Gas - % of NYMEX*:
400% - 500%
400% - 500%
*Note: January and February natural gas
average realized prices were ~$47.50 and ~$10.00 per Mcf,
respectively.
Fourth Quarter & Full Year 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 December
31, 2022, compared to the three months ended September 30, 2022
decreased by approximately 1 MBoe/d, or 1%. This decrease is
predominately a result of CRC's natural decline and lower
development drilling, partially offset by production-sharing
contracts (PSCs), which positively impacted CRC's net oil
production in the three months ended December, 2022 by
approximately 1 MBoe/d, compared to the three months ended
September 30, 2022.
Total daily net production for the year ended December 31, 2022,
compared to the year ended December 31, 2021 decreased by
approximately 9 MBoe/d, or 9%. The decrease was predominately a
result of CRC's natural decline and lower development drilling
which accounted for approximately 4 MBoe/d and divestitures of
certain Ventura basin and Lost Hills assets which accounted for
approximately 5 MBoe/d. See Part II, Item 8 – Financial Statements
and Supplementary Data, Note 3 Divestitures and Acquisitions of
CRC's 2022 10-K for more information on CRC's divestitures in
2022.
During the fourth quarter of 2022, CRC operated an average of
one drilling rig in the San Joaquin Basin and two drilling rigs in
the Los Angeles Basin. During the quarter, CRC drilled 23 net wells
and brought online 23 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.
Fourth Quarter & Full Year 2022
Financial Results
4th Quarter
3rd Quarter
Total Year
Total Year
($ and shares in millions, except per
share amounts)
2022
2022
2022
2021
Statements of
Operations:
Revenues
Total operating revenues
$
682
$
1,125
$
2,707
$
1,889
Operating Expenses
Total operating expenses
549
536
1,954
1,720
Gain on asset divestitures
(1
)
2
59
124
Operating Income
$
132
$
591
$
812
$
293
Net Income Attributable to Common
Stock
$
83
$
426
$
524
$
612
Net income attributable to common stock
per share - basic
$
1.14
$
5.75
$
6.94
$
7.46
Net income attributable to common stock
per share - diluted
$
1.11
$
5.58
$
6.75
$
7.37
Adjusted net income1
$
93
$
111
$
384
$
506
Adjusted net income1 per share -
diluted
$
1.24
$
1.45
$
4.95
$
6.10
Weighted-average common shares outstanding
- basic
72.7
74.1
75.5
82.0
Weighted-average common shares outstanding
- diluted
75.0
76.3
77.6
83.0
Adjusted EBITDAX1
$
208
$
234
$
852
$
860
Review of Fourth Quarter & Full
Year 2022 Financial Results
Realized oil prices, excluding the effects of cash settlements
on CRC's commodity derivative contracts, decreased by $10.81 per
barrel from $97.96 per barrel in the third quarter of 2022 to
$87.15 per barrel in the fourth quarter of 2022. Crude realizations
decreased in the fourth quarter of 2022 relative to the third
quarter of 2022 as California refining margins tightened
significantly leaving those refiners less motivated to secure
incremental barrels.
For the year ended December 31, 2022, realized oil prices,
excluding the effects of cash settlements on CRC's commodity
derivative contracts, increased by $27.83 per barrel to $98.26 from
$70.43 per barrel in the same period of 2021. Capital and
production discipline across domestic and international producers
generally offset continued COVID-19 lockdowns in China, reduced
energy demand across much of Europe and the release of meaningful
quantities of oil from the United States Strategic Petroleum
Reserve.
Realized oil prices, including the effects of cash settlements
on CRC's commodity derivative contracts, decreased by $1.12 from
$62.45 in the third quarter of 2022 to $61.33 in the fourth quarter
of 2022.
For the year ended December 31, 2022, realized oil prices,
including the effects of cash settlements on CRC's commodity
derivative contracts, increased by $5.75 to $61.80 from $56.05 per
barrel in the same period of 2021. See Attachment 4 for further
information on prices.
Adjusted EBITDAX1 for the fourth quarter of 2022 and for the
year ended December 31, 2022, was $208 million and $852 million,
respectively. See table below for the Company's net cash provided
by operating activities, capital investments and free cash flow1
during the same periods.
FREE CASH FLOW1
Management uses free cash flow, which is
defined by CRC as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of CRC's net cash provided by operating
activities to free cash flow. CRC supplemented its non-GAAP measure
of free cash flow with free cash flow of CRC's exploration and
production and corporate items (Free Cash Flow for E&P,
Corporate & Other) which it believes is a useful measure for
investors to understand the results of its core oil and gas
business. CRC defines Free Cash Flow for E&P, Corporate &
Other as consolidated free cash flow less results attributable to
its carbon management business (CMB).
4th Quarter
3rd Quarter
Total Year
Total Year
($ millions)
2022
2022
2022
2021
Net cash provided by operating
activities
$
114
$
235
$
690
$
660
Capital investments
(75
)
(107
)
(379
)
(194
)
Free cash flow1
39
128
311
466
E&P, corporate & other free cash
flow1
$
61
$
139
$
362
$
472
CMB free cash flow1
$
(22
)
$
(11
)
$
(51
)
$
—
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 PSCs 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
Total Year
Total Year
($ per Boe)
2022
2022
2022
2021
Energy operating costs
$
9.56
$
10.96
$
9.76
$
7.01
Gas processing costs
0.48
0.49
0.52
0.54
Non-energy operating costs
13.82
13.82
13.47
11.84
Operating costs
$
23.86
$
25.27
$
23.75
$
19.39
Excess costs attributable to PSCs
$
(1.90
)
(2.16
)
$
(2.23
)
(1.83
)
Operating costs, excluding effects of PSCs
(a)
$
21.96
$
23.11
$
21.52
$
17.56
(a)
Operating costs, excluding
effects of PSCs is a non-GAAP measure.
Energy operating costs for the fourth quarter of 2022 were $80
million, or $9.56 per Boe, which was a decrease of $13 million or
14% from $93 million, or $10.96 per Boe, for the third quarter of
2022. This decrease was primarily a result of lower production and
lower electricity and natural gas prices.
Energy operating costs for the year ended December 31, 2022 were
$323 million, or $9.76 per Boe, which was an increase of $68
million or 27% from $255 million, or $7.01 per Boe, in the same
period of 2021. The increase was predominantly a result of higher
prices for purchased natural gas, which CRC uses to generate
electricity for its operations and steam for its steamfloods, and
for purchased electricity.
Non-energy operating costs for the fourth quarter of 2022 were
$116 million, or $13.82 per Boe, which was a decrease of $1 million
or 1% from $117 million, or $13.82 per Boe, for the third quarter
of 2022. This decrease was primarily a result of lower surface
maintenance.
Non-energy operating costs for the year ended December 31, 2022
were $445 million, or 13.47 per Boe, which was an increase of $15
million or 3% from $430 million, or 11.84 per Boe, in the same
period of 2021. This increase was primarily a result of increased
surface and downhole maintenance activity in 2022.
Sustainability & Carbon Management
Update
In December 2022, Carbon TerraVault JV entered into a CDMA with
Lone Cypress, an independent energy company focused on the
development of low-carbon hydrogen generation facilities and energy
infrastructure, to sequester 100,000 MT of CO2 per annum from a
newly constructed blue hydrogen plant at the Elk Hills Field in
Kern County.
Also in December 2022, CRC received an A- from CDP for its 2022
climate disclosure, securing a score at CDP’s Leadership Level for
the fourth year in a row. This accomplishment is further evidence
of CRC’s commitment to maintaining a strong ESG and sustainability
platform.
In January 2023, CTV entered into a CDMA with Grannus, an
independent clean-tech company that is building a portfolio of blue
ammonia and hydrogen production facilities to supply the
agriculture, mobility and marine fuel markets, to sequester 370,000
MT of CO2 per annum at CTV III from a new blue ammonia and hydrogen
plant to be constructed in Northern California. Called the Grannus
Blue Ammonia and Hydrogen Project, the project aims to be
California’s first blue ammonia and hydrogen facility producing
150,000 MT per annum of blue ammonia and 10,000 MT per annum of
blue hydrogen.
In February 2023, CRC assembled a consortium of organizations
across industry, technology, academia, national labs, community,
government, and labor, to pursue U.S. Department of Energy (DOE)
funding under its Regional DAC Hubs Initiative to create the
California DAC Hub, the state’s first full-scale DAC plus storage
(DAC+S) network of regional DAC+S hubs. DAC+S is a solution that
can remove and then permanently store atmospheric CO2 using low
carbon emission energy and provide economic benefits to surrounding
communities.
The California DAC Hub is expected to accelerate California’s
progress to achieve its carbon neutrality goal while prioritizing
the surrounding under-represented California communities in several
areas including: air quality improvements, increased renewable
energy use and enhanced water management including water
reclamation and production of new water sources. Further, CRC
expects that the hub will provide high quality union jobs while
enhancing local area education programs in science, technology and
math (STEM) along with energy transition.
Balance Sheet and Liquidity
Update
CRC's aggregate commitment under the Revolving Credit Facility
was $602 million as of December 31, 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 December 31, 2022, CRC had liquidity of $765 million,
which consisted of $307 million in unrestricted cash and $458
million of available borrowing capacity under its Revolving Credit
Facility which is net of $144 million of letters of credit.
Acquisitions and
Divestitures
On February 1, 2022, CRC sold its 50% non-operated working
interest in certain horizons within its Lost Hills field, located
in the San Joaquin basin, recognizing a gain of $49 million. CRC
retained an option to capture, transport and store 100% of the CO2
from steam generators across the Lost Hills field for future carbon
management projects. CRC also retained 100% of the deep rights and
related seismic data.
In June 2022, CRC sold its commercial office building located in
Bakersfield, California for net proceeds of $13 million,
recognizing no gain or loss on sale.
During the year ended December 31, 2022, CRC recognized a gain
of $11 million related to the sale of certain Ventura basin assets.
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 it 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 consolidated balance sheet as
of December 31, 2022.
Also in 2022, CRC sold non-core assets recognizing a $1 million
loss and acquired properties for carbon management activities for
~$17 million.
Shareholder Return
Strategy
CRC continues to prioritize shareholder returns and therefore
dedicates a significant portion of its free cash flow to
shareholders in the form of dividends and share repurchases. To
that end, CRC’s Board of Directors approved an increase of the
Share Repurchase Program to $1.1 billion, an increase of $250
million and extended the program through June 30, 2024. Adjusting
for this increase, CRC has $640 million of capacity remaining under
the repurchase program as of December 31, 2022.
During the fourth quarter of 2022, CRC repurchased 1.5 million
shares for $66 million or an average price of $43.17/share. Since
the inception of the Share Repurchase Program in May 2021,
11,456,260 shares have been repurchased for $461 million at an
average price of $40.19 per share. These total repurchases
represent 14% of CRC’s shares outstanding at its bankruptcy
emergence in October 2020.
On February 23, 2023, 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 March 6, 2023 and
will be paid on March 16, 2023.
Through December 31, 2022, CRC has returned $534 million of cash
to its shareholders, including $461 million in share repurchases
and $73 million of dividends. These figures exclude share
repurchases made to-date in 2023 as well as the $20 million fourth
quarter dividend declared and payable in March 2023.
Reserves
As of December 31, 2022, CRC’s proved reserves totaled an
estimated 417 million BOE, of which 363 million BOE was proved
developed and 54 million BOE was proved undeveloped. The estimated
future net cash flows of our proved reserve volumes had a PV-101
value of $9.2 billion. These estimates were based on SEC pricing
and the average realized prices for estimating CRC's PV-101 of cash
flows as of December 31, 2022, were $97.50 per barrel for oil,
$67.83 per barrel for NGLs and $7.84 per Mcf for natural gas.
PV-10 AND STANDARDIZED MEASURE
The following table presents a
reconciliation of the GAAP financial measure of Standardized
Measure of discounted future net cash flows (Standardized Measure)
to the non-GAAP financial measure of PV-10:
($ millions)
December 31, 2022
Standardized Measure of discounted future
net cash flows
$
6,726
Present value of future income taxes
discounted at 10%
2,493
PV-10 of cash flows (*)
$
9,219
(*) 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 our
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.
Upcoming Investor Conference
Participation
CRC's executives will be participating in the following events
in February and March of 2023:
- Credit Suisse Vail Summit on February 26 in Vail, CO
- MS Global Energy and Power Conference on March 1 in New York,
NY
- CERAWeek 2023 on March 6 to 8 in Houston, TX
- 7th Annual Mizuho Energy Summit on March 12 in Napa, CA
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 February 24,
2023, 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 https://dpregister.com/sreg/10173792/f5508a95c0. 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 2023 and 1Q23 estimates of the non-GAAP measure of
free cash flow, including reconciliations to their most directly
comparable GAAP measure, see Attachment 7.
(2)
Calculated as $307 million of
available cash plus $602 million of capacity on CRC's Revolving
Credit Facility less $144 million in outstanding letters of
credit.
(3)
Current guidance assumes a 2023
Brent price of $79.12 per barrel of oil, NGL realizations as a
percentage of Brent consistent with prior years and a NYMEX gas
price of $4.27 per mcf and a 1Q23 Brent price of $79.81 per barrel
of oil, NGL realizations as a percentage of Brent consistent with
prior years and a NYMEX gas price of $4.46 per mcf. CRC's share of
production under PSC contracts decreases when commodity prices rise
and increases when prices fall.
(4)
Adjusted E&P Capital and
Adjusted CMB Capital are Non-GAAP measures. These measures reflect
the reclassification of ~$11 million from E&P, Corporate &
Other Capital to Adjusted CMB Capital related to the expected 2023
investment in facilities to advance carbon sequestration activities
beginning in 2Q23. For the full year 2023 and 1Q23 estimates of the
non-GAAP measure of free cash flow, including reconciliations to
their most directly comparable GAAP measure, see Attachment 7.
(5)
CMB Expenses includes lease cost
for sequestration easements, advocacy, and other startup related
costs.
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 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 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 its forward-looking statements include:
- fluctuations in commodity prices, including supply and demand
considerations for CRC's products and services;
- 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 war in Ukraine and oil sanctions on Russia, Iran and
others;
- regulatory actions and changes that affect the oil and gas
industry generally and CRC in particular, including (1) the
availability or timing of, or conditions imposed on, permits and
approvals necessary for drilling or development activities or CRC's
carbon management business; (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 CRC's products;
- the impact of inflation on future expenses and changes
generally in the prices of goods and services;
- changes in business strategy and CRC's capital plan;
- lower-than-expected production or higher-than-expected
production decline rates;
- changes to CRC's 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 CRC 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 CRC's counterparties,
including financial institutions, operating partners, CCS project
participants and other parties;
- reorganization or restructuring of CRC's operations;
- CRC's ability to claim and utilize tax credits or other
incentives in connection with its 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;
- CRC's ability to successfully develop infrastructure projects
and enter into third party contracts on contemplated terms;
- uncertainty around the accounting of emissions and CRC's
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 CRC's capital plan and other
planned investments and return capital to shareholders;
- changes in interest rates, and CRC's access to and the terms of
credit in commercial banking and capital markets, including its
ability to refinance its debt or obtain separate financing for its
carbon management business;
- 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 CRC's ability to achieve any expected
synergies;
- disruptions due to earthquakes, forest fires, floods 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; 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
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ and shares in millions, except per
share amounts)
2022
2022
2021
2022
2021
Statements of Operations:
Revenues
Oil, natural gas and NGL sales
$
617
$
680
$
589
$
2,643
$
2,048
Net (loss) gain from commodity
derivatives
(132
)
243
(73
)
(551
)
(676
)
Sales of purchased natural gas
94
113
71
314
312
Electricity sales
90
88
41
261
172
Other revenue
13
1
6
40
33
Total operating revenues
682
1,125
634
2,707
1,889
Operating Expenses
Operating costs
199
214
182
785
705
General and administrative expenses
59
59
53
222
200
Depreciation, depletion and
amortization
49
50
53
198
213
Asset impairments
—
—
—
2
28
Taxes other than on income
42
44
32
162
145
Exploration expense
1
1
1
4
7
Purchased natural gas expense
87
98
52
273
196
Electricity generation expenses
68
42
26
167
96
Transportation costs
13
13
14
50
51
Accretion expense
11
10
11
43
50
Other operating expenses, net
20
5
(2
)
48
29
Total operating expenses
549
536
422
1,954
1,720
Net (loss) gain on asset divestitures
(1
)
2
120
59
124
Operating Income
132
591
332
812
293
Non-Operating (Expenses) Income
Reorganization items, net
—
—
(1
)
—
(6
)
Interest and debt expense
(14
)
(13
)
(14
)
(53
)
(54
)
Loss from investment in unconsolidated
subsidiaries
(1
)
—
—
(1
)
—
Net loss on early extinguishment of
debt
—
—
—
—
(2
)
Other non-operating income (expenses),
net
—
1
1
3
(2
)
Net Income Before Income Taxes
117
579
318
761
229
Income tax (provision) benefit
(34
)
(153
)
396
(237
)
396
Net income
83
426
714
524
625
Net income attributable to noncontrolling
interests
—
—
—
—
(13
)
Net Income Attributable to Common
Stock
$
83
$
426
$
714
$
524
$
612
Net income attributable to common stock
per share - basic
$
1.14
$
5.75
$
8.91
$
6.94
$
7.46
Net income attributable to common stock
per share - diluted
$
1.11
$
5.58
$
8.71
$
6.75
$
7.37
Adjusted net income
$
93
$
111
$
175
$
384
$
506
Adjusted net income per share - basic
$
1.28
$
1.50
$
2.18
$
5.09
$
6.17
Adjusted net income per share -
diluted
$
1.24
$
1.45
$
2.13
$
4.95
$
6.10
Weighted-average common shares outstanding
- basic
72.7
74.1
80.1
75.5
82.0
Weighted-average common shares outstanding
- diluted
75.0
76.3
82.0
77.6
83.0
Adjusted EBITDAX
$
208
$
234
$
260
$
852
$
860
Effective tax rate
29
%
26
%
(125
)%
31
%
(173
)%
GAINS AND LOSSES FROM COMMODITY DERIVATIVES
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ millions)
2022
2022
2021
2022
2021
Non-cash derivative gain (loss)
$
2
$
425
$
26
$
187
$
(357
)
Net payments on settled commodity
contracts
(134
)
(182
)
(99
)
(738
)
(319
)
Net (loss) gain from commodity
derivatives
$
(132
)
$
243
$
(73
)
$
(551
)
$
(676
)
CAPITAL INVESTMENTS
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ millions)
2022
2022
2021
2022
2021
Facilities (1)
$
19
$
20
$
14
$
71
$
43
Drilling
48
73
46
242
119
Workovers
14
7
2
36
27
Total E&P capital
81
100
62
349
189
CMB (1)(2)
(13
)
6
—
4
—
Corporate and other
7
1
4
26
5
Total capital program
$
75
$
107
$
66
$
379
$
194
(1)
Total year 2022 facilities
capital includes $12 million 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 and CRC reported
this $12 million of capital as part of adjusted CMB capital in this
press release. Where adjusted CMB capital is presented, CRC removed
$12 million from facilities capital for total E&P, Corporate
and Other.
(2)
In the fourth quarter of 2022,
$14 million of capital investments was reclassified from PP&E
to other noncurrent assets.
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, E&P, Corporate & Other
adjusted EBITDAX, CMB adjusted EBITDAX, free cash flow, E&P,
Corporate & Other free cash flow, CMB free cash flow, adjusted
general and administrative expenses, operating costs per BOE, and
adjusted total capital 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. 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 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
and adjusted net income per share.
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ millions, except per share amounts)
2022
2022
2021
2022
2021
Net income
$
83
$
426
$
714
$
524
$
625
Net income attributable to noncontrolling
interests
—
—
—
—
(13
)
Net income attributable to common
stock
83
426
714
524
612
Unusual, infrequent and other items:
Non-cash derivative (gain) loss
(2
)
(425
)
(26
)
(187
)
357
Asset impairments
—
—
—
2
28
Reorganization items, net
—
—
1
—
6
Severance and termination costs
—
—
—
—
15
Net loss on early extinguishment of
debt
—
—
—
—
2
Net loss (gain) on asset divestitures
1
(2
)
(120
)
(59
)
(124
)
Rig termination expenses
2
—
—
2
2
Other, net
13
4
2
20
4
Total unusual, infrequent and other
items
14
(423
)
(143
)
(222
)
290
Income tax (benefit) provision of
adjustments at effective tax rate
(4
)
120
—
63
—
Income tax (benefit) provision - out of
period
—
(12
)
(396
)
19
(396
)
Adjusted net income attributable to common
stock
$
93
$
111
$
175
$
384
$
506
Net income attributable to common stock
per share - basic
$
1.14
$
5.75
$
8.91
$
6.94
$
7.46
Net income attributable to common stock
per share - diluted
$
1.11
$
5.58
$
8.71
$
6.75
$
7.37
Adjusted net income per share - basic
$
1.28
$
1.50
$
1.85
$
5.09
$
6.17
Adjusted net income per share -
diluted
$
1.24
$
1.45
$
1.83
$
4.95
$
6.10
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 exploration and production and corporate items (Adjusted
EBITDAX for E&P, Corporate & Other) which management
believes is a useful measure for investors to understand the
results of the 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).
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ millions, except per BOE amounts)
2022
2022
2021
2022
2021
Net income
$
83
$
426
$
714
$
524
$
625
Interest and debt expense
14
13
14
53
54
Depreciation, depletion and
amortization
49
50
53
198
213
Income tax provision (benefit)
34
153
(396
)
237
(396
)
Exploration expense
1
1
1
4
7
Interest income
(3
)
(1
)
—
(4
)
—
Unusual, infrequent and other items
(1)
14
(423
)
(143
)
(222
)
290
Non-cash items
Accretion expense
11
10
11
43
50
Stock-based compensation
4
5
4
17
14
Post-retirement medical and pension
1
—
2
2
3
Adjusted EBITDAX
$
208
$
234
$
260
$
852
$
860
Net cash provided by operating
activities
$
114
$
235
$
204
$
690
$
660
Cash interest payments
2
23
2
50
31
Cash interest received
(3
)
(1
)
—
(4
)
—
Cash income taxes
—
—
—
20
—
Exploration expenditures
1
1
1
4
7
Working capital changes
94
(24
)
53
92
162
Adjusted EBITDAX
$
208
$
234
$
260
$
852
$
860
E&P, Corporate & Other Adjusted
EBITDAX
$
223
$
239
$
242
$
879
$
600
CMB Adjusted EBITDAX
$
(15
)
$
(5
)
$
—
$
(27
)
$
—
Adjusted EBITDAX per Boe
$
24.94
$
27.63
$
29.22
$
25.77
$
23.65
(1)
See Adjusted Net Income (Loss)
reconciliation.
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 free cash flow of its exploration and
production and corporate items (Free Cash Flow for E&P,
Corporate & Other) which it believes is a useful measure for
investors to understand the results of CRC's core oil and gas
business. CRC defines Free Cash Flow for E&P, Corporate &
Other as consolidated free cash flow less results attributable to
its carbon management business (CMB).
CRC has also excluded bankruptcy related
fees during 2021 as a supplemental measure of its free cash
flow.
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ millions)
2022
2022
2021
2022
2021
Net cash provided by operating
activities
$
114
$
235
$
204
$
690
$
660
Capital investments
(75
)
(107
)
(66
)
(379
)
(194
)
Free cash flow
39
128
138
311
466
Bankruptcy related fees
—
—
1
—
6
Free cash flow, after special items
$
39
$
128
$
139
$
311
$
472
E&P, Corporate and Other Free Cash
Flow
$
61
$
139
$
139
$
362
$
472
CMB Free Cash Flow
$
(22
)
$
(11
)
$
—
$
(51
)
$
—
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. CRC supplemented its non-GAAP
measure of adjusted general and administrative expenses with
adjusted general and administrative expenses of its exploration and
production and corporate items (Adjusted General &
Administrative Expenses for E&P, Corporate & Other) which
it believes is a useful measure for investors to understand the
results for CRC's core oil and gas business. CRC defines Adjusted
General & Administrative Expenses for E&P, Corporate &
Other as consolidated adjusted general and administrative expenses
less results attributable to its carbon management business
(CMB).
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
($ millions)
2022
2022
2021
2022
2021
General and administrative expenses
$
59
$
59
$
53
$
222
$
200
Stock-based compensation
(4
)
(5
)
(4
)
(17
)
(14
)
Other
(2
)
(1
)
—
(4
)
—
Adjusted G&A expenses
$
53
$
53
$
49
$
201
$
186
E&P, Corporate and Other Adjusted
G&A expenses
$
51
$
48
$
49
$
189
$
186
CMB Adjusted G&A expenses
$
2
$
5
$
—
$
12
$
—
OPERATING COSTS PER BOE
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)
2022
2022
2021
2022
2021
Energy operating costs (1)
$
9.56
$
10.96
$
8.04
$
9.76
$
7.01
Gas processing costs (2)
0.48
0.49
0.41
0.52
0.54
Non-energy operating costs (3)
13.82
13.82
12.00
13.47
11.84
Operating costs
$
23.86
$
25.27
$
20.45
$
23.75
$
19.39
Costs attributable to PSCs
Excess energy operating costs attributable
to PSCs
$
(0.76
)
$
(0.97
)
$
(0.82
)
$
(0.92
)
$
(0.68
)
Excess non-energy operating costs
attributable to PSCs
(1.14
)
(1.19
)
(1.31
)
(1.31
)
(1.15
)
Excess costs attributable to
PSCs
$
(1.90
)
$
(2.16
)
$
(2.13
)
$
(2.23
)
$
(1.83
)
Energy operating costs, excluding effect
of PSCs (1)
$
8.80
$
9.99
$
7.22
$
8.84
$
6.33
Gas processing costs, excluding effect of
PSCs (2)
0.48
0.49
0.41
0.52
0.54
Non-energy operating costs, excluding
effect of PSCs (3)
12.68
12.63
10.69
12.16
10.69
Operating costs, excluding effects of
PSCs
$
21.96
$
23.11
$
18.32
$
21.52
$
17.56
(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. 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.
Attachment 3
PRODUCTION STATISTICS
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
Net Production Per Day
2022
2022
2021
2022
2021
Oil (MBbl/d)
San Joaquin Basin
36
36
40
37
39
Los Angeles Basin
19
19
18
18
19
Ventura Basin
—
—
1
—
2
Total
55
55
59
55
60
NGLs (MBbl/d)
San Joaquin Basin
11
12
12
11
13
Total
11
12
12
11
13
Natural Gas (MMcf/d)
San Joaquin Basin
129
131
131
129
135
Los Angeles Basin
1
1
1
1
1
Ventura Basin
—
—
2
—
4
Sacramento Basin
17
17
19
17
19
Total
147
149
153
147
159
Total Production (MBoe/d)
91
92
97
91
100
Gross Operated and Net
Non-Operated
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
Production Per Day
2022
2022
2021
2022
2021
Oil (MBbl/d)
San Joaquin Basin
40
40
45
41
45
Los Angeles Basin
25
26
26
25
27
Ventura Basin
—
—
1
—
2
Total
65
66
72
66
74
NGLs (MBbl/d)
San Joaquin Basin
12
13
13
12
13
Total
12
13
13
12
13
Natural Gas (MMcf/d)
San Joaquin Basin
136
140
138
136
142
Los Angeles Basin
8
7
7
7
8
Ventura Basin
—
—
2
—
4
Sacramento Basin
21
21
24
22
24
Total
165
168
171
165
178
Total Production (MBoe/d)
105
107
114
106
117
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
4th Quarter
3rd Quarter
4th Quarter
Total Year
Total Year
2022
2022
2021
2022
2021
Oil ($ per Bbl)
Realized price with derivative
settlements
$
61.33
$
62.45
$
61.00
$
61.80
$
56.05
Realized price without derivative
settlements
$
87.15
$
97.96
$
78.99
$
98.26
$
70.43
NGLs ($/Bbl)
$
56.55
$
57.68
$
67.61
$
64.33
$
53.62
Natural gas ($/Mcf)
Realized price with derivative
settlements
$
8.51
$
8.58
$
5.94
$
7.54
$
4.20
Realized price without derivative
settlements
$
8.73
$
8.80
$
5.94
$
7.68
$
4.22
Index Prices
Brent oil ($/Bbl)
$
88.60
$
97.81
$
79.80
$
98.89
$
70.79
WTI oil ($/Bbl)
$
82.64
$
91.56
$
77.19
$
94.23
$
67.91
NYMEX contract month average ($/MMBtu)
$
6.76
$
7.85
$
5.27
$
6.36
$
3.61
NYMEX average monthly settled price
($/MMBtu)
$
6.26
$
8.20
$
5.83
$
6.64
$
3.84
Realized Prices as Percentage of Index
Prices
Oil with derivative settlements as a
percentage of Brent
69
%
64
%
76
%
62
%
79
%
Oil without derivative settlements as a
percentage of Brent
98
%
100
%
99
%
99
%
99
%
Oil with derivative settlements as a
percentage of WTI
74
%
68
%
79
%
66
%
83
%
Oil without derivative settlements as a
percentage of WTI
105
%
107
%
102
%
104
%
104
%
NGLs as a percentage of Brent
64
%
59
%
85
%
65
%
76
%
NGLs as a percentage of WTI
68
%
63
%
88
%
68
%
79
%
Natural gas with derivative settlements as
a percentage of NYMEX contract month average
126
%
109
%
113
%
119
%
116
%
Natural gas with derivative settlements as
a percentage of NYMEX average monthly settled price
136
%
105
%
102
%
114
%
109
%
Natural gas without derivative settlements
as a percentage of NYMEX contract month average
129
%
112
%
113
%
121
%
117
%
Natural gas without derivative settlements
as a percentage of NYMEX average monthly settled price
139
%
107
%
102
%
116
%
110
%
Attachment 5
FOURTH QUARTER 2022 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
1
—
—
—
1
Waterflood
—
16
—
—
16
Steamflood
6
—
—
—
6
Total (1)
7
16
—
—
23
TOTAL YEAR 2022 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
18
—
—
—
18
Waterflood
27
41
—
—
68
Steamflood
61
—
—
—
61
Total (1)
106
41
—
—
147
(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 DECEMBER 31,
2022
Q1 2023
Q2 2023
Q3 2023
Q4 2023
2024
Sold Calls
Barrels per day
18,322
17,837
17,363
5,747
—
Weighted-average Brent price per
barrel
$57.28
$60.00
$57.06
$57.06
—
Swaps
Barrels per day
16,620
16,475
16,697
26,094
1,492
Weighted-average Brent price per
barrel
$69.46
$68.53
$68.33
$70.18
$79.06
Net Purchased Puts (1)
Barrels per day
18,322
17,837
17,363
5,747
1,724
Weighted-average Brent price per
barrel
$76.25
$76.25
$76.25
$76.25
$75.00
(1)
Purchased puts and sold puts with
the same strike price have been presented on a net basis.
Attachment 7
2023 Estimated
TOTAL CRC GUIDANCE1
Consolidated
CMB
E&P, Corporate &
Other
Net Total Production (MBoe/d)
85 - 91
85 - 91
Net Oil Production (MBbl/d)
51 - 55
51 - 55
Operating Costs ($ millions)
$845 - $895
$845 - $895
CMB Expenses2 ($ millions)
$25 - $35
$25 - $35
Adjusted General and Administrative
Expenses ($ millions)
$195 - $225
$10 - $15
$185 - $210
Total Capital ($ millions)
$200 - $245
$5 - $15
$195 - $230
Adjusted Total Capital3 ($ millions)
$200 - $245
$15 - $25
$185 - $220
Free Cash Flow ($ millions)
$330 - $440
($60) - ($80)
$410 - $500
Natural Gas Trading, Net ($ millions)
$60 - $70
$60 - $70
Net Electricity ($ millions)
$80 - $120
$80 - $120
Transportation Expense ($ millions)
$50 - $70
$50 - $70
ARO Settlement Payments* ($ millions)
$55 - $60
$55 - $60
Taxes Other Than on Income* ($
millions)
$175 - $185
$175 - $185
Interest and Debt Expense* ($
millions)
$55 - $60
$55 - $60
Cash Income Taxes* ($ millions)
$80 - $100
$80 - $100
Commodity Realizations:
Oil - % of Brent:
97% - 99%
97% - 99%
NGL - % of Brent:
58% - 64%
58% - 64%
Natural Gas - % of NYMEX*:
150% - 250%
150% - 250%
*Notes:
- 2023E ARO Settlement Payments: ~25% of estimated annual amount
is paid every quarter
- 2023E Taxes Other Than on Income: ~30% of estimated annual
amount is paid in 1Q and 4Q, respectively
- 2023E Interest Expense: ~46% of estimated annual amount is paid
in cash in 1Q and 3Q, respectively
- Cash Income Taxes aren’t paid evenly throughout 2023
- Note: January and February natural gas average realized prices
were ~$47.50 and ~$10.00 per Mcf, respectively.
1Q23 Estimated
Total CRC GUIDANCE1
Consolidated
CMB
E&P, Corporate &
Other
Net Total Production (MBoe/d)
89 - 91
89 - 91
Net Oil Production (MBbl/d)
53 - 54
53 - 54
Operating Costs ($ millions)
$260 - $270
$260 - $270
CMB Expenses2 ($ millions)
$5 - $10
$5 - $10
Adjusted General and Administrative
Expenses ($ millions)
$50 - $58
$3 - $5
$47 - $53
Total Capital ($ millions)
$57 - $69
$2 - $4
$55 - $65
Adjusted Total Capital3 ($ millions)
$57 - $69
$2 - $4
$55 - $65
Free Cash Flow ($ millions)
$151 - $180
($15) - ($24)
$175 - $195
Natural Gas Trading, Net ($ millions)
$35 - $45
$35 - $45
Net Electricity ($ millions)
$25 - $35
$25 - $35
Transportation Expense ($ millions)
$14 - $16
$14 - $16
Commodity Realizations:
Oil - % of Brent:
97% - 99%
97% - 99%
NGL - % of Brent:
63% - 65%
63% - 65%
Natural Gas - % of NYMEX:
400% - 500%
400% - 500%
See Attachment 2 for management's disclosure of its use of these
non-GAAP measures and how these measures provide useful information
to investors about CRC's results of operations and financial
condition. CRC has supplemented its non-GAAP measures of
consolidated free cash flow with free cash flow from our
exploration and production and corporate items (free cash flow from
E&P, Corporate & Other) which CRC believes is a useful
measure for investors to understand the results of its core oil and
gas business. CRC defines free cash flow from E&P, Corporate
& Other as consolidated free cash flow less free cash flow
attributable to CMB.
ESTIMATED FREE CASH FLOW
RECONCILIATION
2023 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
Net cash provided (used) by operating
activities
$
575
$
640
$
(55
)
$
(45
)
$
630
$
685
Adjusted capital investments3
(245
)
(200
)
(25
)
(15
)
(220
)
(185
)
Estimated free cash flow
$
330
$
440
$
(80
)
$
(60
)
$
410
$
500
1Q23 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
Net cash provided (used) by operating
activities
$
220
$
237
$
(20
)
$
(13
)
$
240
$
250
Capital investments
(69
)
(57
)
(4
)
(2
)
(65
)
(55
)
Estimated free cash flow
$
151
$
180
$
(24
)
$
(15
)
$
175
$
195
ESTIMATED ADJUSTED GENERAL AND
ADMINISTRATIVE EXPENSES RECONCILIATION
2023 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
General and administrative expenses
$
235
$
250
$
10
$
15
$
225
$
235
Equity-settled stock-based
compensation
(25
)
(15
)
(25
)
(15
)
Other
(15
)
(10
)
(15
)
(10
)
Estimated adjusted general and
administrative expenses
$
195
$
225
$
10
$
15
$
185
$
210
1Q23 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
General and administrative expenses
$
62
$
66
$
3
$
5
$
59
$
61
Equity-settled stock-based
compensation
(7
)
(5
)
(7
)
(5
)
Other
(5
)
(3
)
(5
)
(3
)
Estimated adjusted general and
administrative expenses
$
50
$
58
$
3
$
5
$
47
$
53
(1)
2023E guidance assumes a 2023
Brent price of $79.12 per barrel of oil, NGL realizations
consistent with prior years and an average daily NYMEX gas price of
$4.27 per mcf. 1Q23E guidance assumes a 1Q23 Brent price of $79.81
per barrel of oil, NGL realizations consistent with prior years and
an average daily NYMEX gas price of $4.46 per mcf. CRC’s share of
production under PSCs decreases when commodity prices rise and
increases when prices decline.
(2)
CMB Expenses includes lease cost
for sequestration easements, advocacy, and other startup related
costs.
(3)
Adjusted E&P Capital and
Adjusted CMB Capital are Non-GAAP measures. These measures reflect
~$11 million from E&P, Corporate & Other Capital to
Adjusted CMB Capital related to the expected 2023 investment in
facilities to advance carbon sequestration activities beginning in
2Q23.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20230224005093/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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