California Resources Corporation (NYSE: CRC), an independent oil
and natural gas company committed to energy transition in the
sector, today announced the formation of a joint venture (the "JV")
with Brookfield Renewable ("Brookfield"), creating a carbon
management partnership focused on carbon capture and sequestration
(“CCS”) development and reported second quarter 2022 operational
and financial results.
Brookfield has committed an initial $500 million to invest in
CCS projects that are jointly approved through the JV. The
investment from Brookfield will be allocated through the Brookfield
Global Transition Fund (“BGTF”), the world’s largest fund dedicated
to facilitating the global transition to a net zero carbon economy.
Brookfield, together with its institutional partners, will
participate in the joint venture through BGTF. The first CCS
project designated for development is CRC’s 26R reservoir in the
Elk Hills Field which was contributed to the partnership at a value
of $10 per metric ton, which will be paid in three installments
with the last two installments subject to achievement of specific
milestones. The initial Brookfield commitment provides CRC with
additional capital to advance the Company's carbon management
strategy, de-risks its CCS projects and aims to significantly
progress the decarbonization of California. The JV is targeting the
injection of 5 million metric tons per annum and 200 million metric
tons of total carbon dioxide ("CO2") storage development, aligned
with CRC’s 2027 goals. Reaching this target would require an
estimated $2.5 billion of total capital, and Brookfield could make
additional investments of more than $1 billion in the strategic
partnership assuming it fully participates in these CCS
projects.
The strategic partnership will benefit substantially from CRC’s
first mover advantage in gaining access to available storage assets
in the state of California and Brookfield’s knowledge in global
clean energy markets. California is a world-leading location for
the development of CCS projects, driven by the state’s Low Carbon
Fuel Standard and Cap-and-Trade programs, together with the federal
45Q tax credit of $50 per ton of CO2 captured and permanently
stored. CRC is currently progressing CO2 storage project permit
applications and represents four out of the five Class VI well
project applications active in California.
"We are pleased to partner with Brookfield to develop industry
leading CCS projects that support California's energy transition,"
said Mac McFarland, CRC’s President and Chief Executive Officer.
"The Brookfield partnership aligns our carbon management strategy
with a strong investment partner, bringing significant operational
and development expertise to reinforce our efforts. Brookfield's
capital commitment also accelerates our carbon management
opportunities. It also enables CRC to maintain capital discipline
and financial flexibility to achieve our corporate objectives
including achieving our Full-Scope Net Zero 2045 goal."
“Transitioning our economy to net zero is a critical global
challenge and that means rapidly scaling our available
decarbonization technologies," said Connor Teskey, CEO of
Brookfield Renewable. "Brookfield Renewable has been a leader in
delivering clean energy for three decades and now we see
significant potential in the rollout of carbon capture and
sequestration technology. Partnering with CRC presents a great
opportunity to continue the growth of our CCS business and expand
the scope of decarbonization solutions we provide to our
customers."
California Carbon Management
Partnership Highlights
- CRC and Brookfield will jointly develop CCS projects in
California through created JVs. The JVs will be owned 51% by CRC
and 49% by BGTF
- The California Carbon Management Partnership with Brookfield is
an important step in CRC’s Full-Scope Net Zero 2045 Goal and Carbon
Management Strategy. It highlights the value of CRC's expansive CO2
pore space portfolio while demonstrating the Company’s commitment
to capital discipline and retaining flexibility for strategic
corporate objectives including shareholder returns and investing in
the business
- Strengthens CRC’s competitive position in CCS deployment with
Brookfield’s infrastructure investment experience, operating
knowledge, and capital allocation. CRC and Brookfield are targeting
the injection of 5 million metric tons of CO2 per annum over the
first five years of the strategic partnership
- CRC is committing $2.5 million over the next three years to the
Kern Community College District (Kern CCD) and California State
University Bakersfield (CSUB) to promote innovation and
implementation of energy transition in California
Second Quarter Operational and
Financial Results
"During the second quarter of 2022, CRC continued to deliver
strong operational results and shareholder returns," said Mac
McFarland. "We expect to maintain our 2022 entry to exit net total
production after taking into account asset divestitures. We are
raising our full year EBITDAX1 and free cash flow guidance1 despite
cost inflation and other macro pressures. With respect to our
shareholder return strategy, CRC returned approximately 134% of its
total generated free cash flow1 back to its shareholders in the
form of dividends and share repurchases. The combination of our
strong financial results coupled with ongoing capital investment
and shareholder return strategies demonstrate our balanced
commitment to our stakeholders."
McFarland continued, "Given prevailing market conditions, we are
raising our adjusted EBITDAX1 and free cash flow1 guidance, and
expect to continue our robust shareholder returns despite
inflationary cost pressures. Further, the strategic partnership
with Brookfield advances our carbon management energy transition
efforts and provides increased capital flexibility with which we
expect to pursue our overall corporate objectives and deliver on
our financial goals and sustainability targets."
Primary Highlights
- Raising full year 2022 adjusted EBITDAX1 and free cash flow1
guidance and reaffirming full year 2022 total production guidance
of 91 to 94 thousand barrels of oil equivalent per day
- Investing approximately $13 million in natural gas assets
located in the Sacramento Basin and the Buena Vista field to focus
on quick and high impact workover opportunities
- In July 2022, CRC's fifth drilling rig began operations at the
Wilmington Field
- Repurchased 2,255,445 common shares for $96 million during the
second quarter of 2022; repurchased an aggregate 9,136,836 shares
for $360 million since the inception of the Share Repurchase
Program through July 31, 2022 for an average price of $39.34 per
share
- Returned $193 million in total shareholder returns to investors
throughout the first half of 2022, 34% more than the total free
cash flow1 generated during the same period
- Declared a quarterly dividend of $0.17 per share of common
stock, totaling $13 million payable on September 16, 2022 to
shareholders of record on September 1, 2022, with subsequent
quarterly dividends subject to final determination and Board
approval
Financial
- Reported net income of $190 million, or $2.41 per fully 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 $89 million,
or $1.13 per fully diluted share
- Generated net cash provided by operating activities of $181
million, adjusted EBITDAX1 of $204 million and free cash flow1 of
$83 million
- Ended the quarter with $324 million of cash on hand, an undrawn
credit facility and $740 million of liquidity2
Operations
- Produced an average of 91,000 net barrels of oil equivalent per
day (Boe/d), including 54,000 barrels of oil per day (Bo/d), with
capital expenditures of $98 million during the quarter
- Operated three drilling rigs in the San Joaquin Basin and one
drilling rig in the Los Angeles Basin; drilled 46 wells (42 online
in 2Q22)
- Operated 33 maintenance rigs
Joint Venture Overview
The carbon management partnership will involve developing both
infrastructure and storage assets required for CCS projects in
California through newly created joint venture entities, Carbon
TerraVault JV HoldCo, LLC ("HoldCo"), Carbon TerraVault JV Storage
Company (“StorageCo”) and Carbon TerraVault JV Infrastructure
Company, LLC (“InfraCo”).
StorageCo will build, install, operate, and maintain CO2 storage
facilities. CRC has contributed the storage rights in the 26R
storage reservoir in the Elk Hills field to StorageCo. Brookfield
has acquired an indirect 49% interest in StorageCo at an implied
value of $10 per metric ton of permitted capacity, payable in three
installments for a total consideration of $137 million. The first
installment of $45.7 million was funded at close. The second and
third installments are due upon completion of certain pre-agreed
milestones related to the permitting process with the EPA and final
investment decision. Future storage projects for Brookfield's
initial commitment will be contributed on the same terms and
milestones.
InfraCo will build, install, operate, maintain CO2 capture
equipment and transportation assets, and provide funding as
projects develop. StorageCo and InfraCo are wholly owned by
HoldCo.
2022 Production Guidance and Capital
Program Update3
CRC's capital program is dynamic in response to oil market
volatility and focused on maintaining oil production and strong
liquidity and maximizing free cash flow. CRC is increasing its 2022
total capital program to a range of $380 to $410 million from $340
million to $385 million. CRC increased its 2022 capital program for
inflation and these cost increases could also impact its capital
program in 2023 and beyond. Additionally, in response to the
continued strong commodity environment, CRC is adding to its
workover program for natural gas assets located in the Sacramento
Basin and the Buena Vista field. Finally, CRC has increased its
capital program for its carbon management activities.
This level of expected spending is consistent with CRC's
strategy of investing up to 50% of its operating cash flow back
into CRC's oil and gas operations. Following the joint venture with
Brookfield, CRC anticipates that a portion of the operating cash
flow previously designated for advancing decarbonization and other
emission reducing projects will now be available for other
corporate purposes, such as shareholder returns and other strategic
opportunities (see a summary of our Business Strategy in Part I,
Item 1 & 2 – Business and Properties in CRC's 2021 Annual
Report).
The delay in the Kern County EIR litigation (see Part I, Item 2
– Management’s Discussion and Analysis of Financial Condition and
Results of Operations, Regulatory Update in the Form 10-Q for the
quarter ended June 30, 2022 for additional details on Kern County
EIR) led to a change in CRC's drilling program which favors a
higher natural gas to oil ratio. Therefore, CRC's 2022 oil
production guidance is expected to be negatively impacted by
approximately 1,000 Bo/d from this change as well as for 1,200
Boe/d for PSC. CRC's 2022 total production guidance remains
consistent with previous expectations in the range of 91 to 94
MBoe/d.
With this capital program, and when adjusted for asset
divestitures, production-sharing contracts (PSC) effects and the
previously discussed Kern County EIR driven change in well mix, CRC
expects to modestly grow oil production from entry to exit and is
maintaining its total net production guidance. During the second
half of 2022, CRC plans to run five drilling rigs in the Elk Hills,
Buena Vista and Wilmington fields. In July 2022, CRC's fifth
drilling rig began operations at the Wilmington Field.
In addition, CRC is raising its free cash flow1 and adjusted
EBITDAX1 guidance by 10% and 2% at the midpoint, respectively, to
$365 to $450 million and $895 to $960 million.
CRC is also raising its operating cost guidance to $725 to $755
million from $680 to $720 million due to inflation, change in well
mix and higher natural gas and electricity prices.
Adjusted G&A guidance increased by $15 million to $185 to
$200 million due primarily to wage and cost inflation as well as
increased headcount as we develop our carbon management
business.
TOTAL CRC GUIDANCE3
2022E
CMB 2022E
E&P, Corp. & Other
2022E
Net Total Production (MBoe/d)
94 - 91
94 - 91
Net Oil Production (MBbl/d)
58 - 53
58 - 53
Operating Costs ($ millions)
$725 - $755
$725 - $755
CMB Expenses4 ($ millions)
$20 - $30
$20 - $30
Adjusted General and Administrative
Expenses1 ($ millions)
$185 - $200
$10 - $15
$175 - $185
Total Capital ($ millions)
$380 - $410
$20 - $30
$360 - $380
Drilling & Completions
$260 - $265
$260 - $265
Workovers
$40 - $45
$40 - $45
Facilities
$55 - $60
$55 - $60
Corporate & Other
$5 - $10
$5 - $10
CMB
$20 - $30
$20 - $30
Adjusted EBITDAX1 ($ millions)
$895 - $960
($30) - ($45)
$940 - $990
Free Cash Flow1 ($ millions)
$365 - $450
($50) - ($75)
$440 - $500
Supporting Local Communities and
Investing in the Energy Transition in California
Aligning with the strategic partnership, CRC will donate $2.5
million over the next three years to Kern Community College
District (Kern CCD) and California State University Bakersfield
(CSUB) to promote innovation and deployment of energy transition in
California. This donation is expected to accelerate R&D efforts
in decarbonization technologies in local academic research
institutions located where CRC operates. CRC is dedicated to
reducing emissions in California and is aligned with the state’s
ambitious climate goals. As part of this pledge, CRC is also
forming the CRC Carbon Management Institute at Kern CCD and is
starting the CRC Energy Transition Lecture Series at CSUB.
Supply Chain and Cost
Inflation
Operating and capital costs in the oil and natural gas industry
are heavily influenced by commodity price environments which are
cyclical in nature. Typically, suppliers will negotiate increases
for drilling and completion, oilfield services, equipment and
materials as prices for energy-related commodities and raw
materials (such as steel, metals and chemicals) increase. Recent
worldwide and U.S. supply chain issues, together with rising
commodity prices and tight labor markets in the U.S., have created
cost inflation during 2022 which may continue in future periods.
CRC has taken proactive measures to limit the effects of the
inflationary market by entering into contracts for materials and
services with terms of one to three years. CRC has also taken steps
to build its on-hand supply stock for items frequently used in its
operations to address possible supply chain disruptions. Despite
these efforts, CRC has experienced increased costs thus far in 2022
and CRC anticipates potential additional increases in the cost of
goods and services and wages in its operations during the remainder
of 2022. These increases have been factored into CRC's operating
and capital costs guidance and could also negatively impact its
results of operations and cash flows in 2023 and beyond.
Second Quarter 2022 E&P Operational
Results
In November 2020, the SEC amended Regulation S-K to, among other
things, provide companies with the option to discuss material
changes to results of operations between the current and
immediately preceding quarter. CRC has elected to discuss its
results of operations on a sequential-quarter basis. CRC believes
this approach provides more meaningful and useful information to
measure its performance from the immediately preceding quarter. In
accordance with this final rule, CRC is not required to include a
comparison of the current quarter and the same prior-year
quarter.
Total daily net production for the three months ended June 30,
2022, compared to the three months ended March 31, 2022 increased
by approximately 3 MBoe/d, or 3%. This increase includes
approximately 5 MBoe/d resulting from the return of production at
one of CRC's cryogenic gas processing facilities, which had planned
maintenance during the first quarter of 2022. These increases were
partially offset by decreases resulting from natural decline, and
the divestiture of CRC's remaining 50% working interest in certain
zones in the Lost Hills field in February 2022. CRC's PSCs
negatively impacted its net oil production in the three months
ended June 30, 2022 by approximately 1 MBoe/d, compared to the
three months ended March 31, 2022. The previously mentioned delays
in the Kern County EIR litigation also negatively affected CRC's
net oil production by 200 Bo/d for the three months ended June 30,
2022 due to the change in well mix.
During the second quarter of 2022, CRC operated an average of
three drilling rigs in the San Joaquin Basin and one drilling rig
in the Los Angeles Basin. During the quarter, CRC drilled 46 net
wells and brought online 42 wells. See Attachment 3 for further
information on CRC's production results by basin and Attachment 5
for further information on CRC's drilling activity.
Second Quarter 2022 Financial
Results
2nd Quarter
1st Quarter
($ and shares in millions, except per
share amounts)
2022
2022
Statements of
Operations:
Revenues
Total operating revenues
$
747
$
153
Operating Expenses
Total operating expenses
473
396
Gain on asset divestitures
4
54
Operating Income (Loss)
$
278
$
(189
)
Net Income (Loss) Attributable to
Common Stock
$
190
$
(175
)
Net income (loss) per share - basic
$
2.48
$
(2.23
)
Net income (loss) per share - diluted
$
2.41
$
(2.23
)
Adjusted net income1
$
89
$
91
Adjusted net income1 per share -
diluted
$
1.13
$
1.13
Weighted-average common shares outstanding
- basic
76.7
78.5
Weighted-average common shares outstanding
- diluted
78.8
78.5
Adjusted EBITDAX1
$
204
$
206
2nd Quarter
1st Quarter
($ in millions)
2022
2022
Cash Flow
Data:
Net cash provided by operating
activities
$
181
$
160
Net cash used in investing activities
$
(76
)
$
(53
)
Net cash used in financing activities
$
(109
)
$
(84
)
Review of Second Quarter 2022 Financial
Results
Realized oil prices, excluding the effects of cash settlements
on CRC's commodity derivative contracts, increased by $16.19 per
barrel from $96.13 per barrel in the first quarter of 2022 to
$112.32 per barrel in the second quarter of 2022. Realized oil
prices were higher in the second quarter of 2022 compared to the
first quarter of 2022 as the effects of the COVID-19 pandemic have
subsided leaving crude oil production and product inventories at
historically low levels. As demand has rebounded, producers have
generally maintained capital discipline, OPEC+ members have failed
to produce at stepped-up quotas, and the conflict between Russia
and Ukraine has created a disconnect between buyers and sellers of
Russian produced crude oil.
Realized oil prices, including the effects of cash settlements
on CRC's commodity derivative contracts, increased by $2.87 from
$60.30 in the first quarter of 2022 to $63.17 in the second quarter
of 2022. The increase is due to a higher commodity price
environment in the second quarter of 2022 compared to the first
quarter of 2022. See Attachment 4 for further information on
prices.
Adjusted EBITDAX1 for the second quarter of 2022 was $204
million. See table below for the Company's net cash provided by
operating activities, capital investments and free cash flow1
during the same periods.
FREE CASH FLOW1
Management uses free cash flow, which is
defined by us as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of our net cash provided by operating
activities to free cash flow. We supplemented our non-GAAP measure
of free cash flow with free cash flow of our exploration and
production and corporate items (Free Cash Flow for E&P,
Corporate & Other) which we believe is a useful measure for
investors to understand the results of our core oil and gas
business. We define Free Cash Flow for E&P, Corporate &
Other as consolidated free cash flow less results attributable to
our carbon management business.
2nd Quarter
1st Quarter
($ millions)
2022
2022
Net cash provided by operating
activities
$
181
$
160
Capital investments
(98
)
(99
)
Free cash flow1
$
83
$
61
E&P, corporate & other free cash
flow1
$
98
$
64
CMB free cash flow1
$
(15
)
$
(3
)
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 purchases of natural gas
used to generate electricity, purchased electricity and internal
costs to generate electricity used in CRC's operations. Non-energy
operating costs equal total operating costs less energy and gas
processing costs. However, non-energy operating costs include the
costs of purchasing natural gas from third parties that is used to
generate steam for CRC's steamflood operations.
OPERATING COSTS PER BOE
The reporting of our PSCs creates a
difference between reported operating costs, which are for the full
field, and reported volumes, which are only our net share,
inflating the per barrel operating costs. The following table
presents operating costs after adjusting for the excess costs
attributable to PSCs.
2nd Quarter
1st Quarter
($ per Boe)
2022
2022
Energy operating costs
$
6.88
6.68
Gas processing costs
0.54
0.56
Non-energy operating costs
15.50
15.63
Operating costs
$
22.92
$
22.87
Excess costs attributable to PSCs
(2.58
)
(2.30
)
Operating costs, excluding effects of PSCs
(a)
$
20.34
$
20.57
(a) Operating costs, excluding effects of
PSCs is a non-GAAP measure.
Energy operating costs for the second quarter of 2022 were $57
million, or $6.88 per Boe, which was an increase of $4 million or
8% from $53 million, or $6.68 per Boe, for the first quarter of
2022. These increases were primarily a result of higher prices for
purchased natural gas, which CRC used to generate electricity for
its operations, and for purchased electricity. Energy operating
costs were also higher on a per Boe basis as a result of lower
production volumes between periods.
Non-energy operating costs for the second quarter of 2022 were
$129 million, or 15.50 per Boe, which was an increase of $5 million
or 4% from $124 million, or $15.63 per Boe, for the first quarter
of 2022. This increase was primarily a result of higher
compensation-related expenses and increased downhole maintenance
activity.
Balance Sheet and Liquidity
Update
CRC's aggregate commitment under the Revolving Credit Facility
was $552 million as of June 30, 2022. The borrowing base for the
Revolving Credit Facility is redetermined semi-annually and was
reaffirmed at $1.2 billion on April 29, 2022.
As of June 30, 2022, CRC had liquidity of $740 million, which
consisted of $324 million in cash and $416 million of available
borrowing capacity under its Revolving Credit Facility.
Acquisitions and
Divestitures
During the three months ended June 30, 2022, CRC recorded a gain
of $4 million related to the sale of certain Ventura basin assets.
The amount recognized in the three months ended June 30, 2022 of $4
million related to additional earn-out consideration on closings
that occurred in the second half of 2021 and the first half of
2022. In addition, CRC received $2 million to secure the
performance of abandonment obligations which CRC expects to
reimburse to the buyer once the abandonment obligations are met. As
a result, CRC recorded a liability of $2 million as of June 30,
2022, and CRC did not recognize gain on asset divestitures for this
portion of the transaction. CRC expects to divest of its remaining
assets in the Ventura basin during the second half of 2022, pending
final approval from the State Lands Commission.
In June 2022, CRC sold its commercial office building located in
Bakersfield, California for net proceeds of $13 million. In May
2022, CRC recorded a $2 million impairment charge to write down the
carrying value of the building to its fair value.
Shareholder Returns
Strategy
CRC continues to prioritize shareholder returns and dedicate a
portion of its operating cash flow to shareholders. In light of
this strategy, CRC's Board of Directors has authorized a Share
Repurchase Program of $650 million, of which $290 million remains
available for future repurchases.
During the second quarter of 2022, CRC repurchased 2.3 million
shares of its common stock for $96 million. During the first half
of 2022, CRC repurchased approximately 3.9 million shares of its
common stock for $167 million. Since the inception of Share
Repurchase Program through July 31, 2022, CRC has repurchased 9.1
million shares for $360 million at an average price of $39.34 per
share, resulting in the repurchase of approximately 11% of the
shares that CRC had at its emergence from bankruptcy.
On August 3, 2022, CRC's Board of Directors declared a quarterly
cash dividend of $0.17 per share of common stock. The dividend is
payable to shareholders of record on September 1, 2022, and will be
paid on September 16, 2022.
Upcoming Investor Conference
Participation
CRC's executives will be participating in the following
in-person events in September 2022:
- Barclays CEO Energy Power Conference on September 6 - 8, 2022,
in New York, NY
- Pickering Energy Partners TE&MFest Conference on September
15 -16, 2022, in Austin, TX
- Credit Suisse 8th Annual Houston Oil & Gas Conference on
September 20 - 21, 2022, in Houston, TX
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.
Advisors
Guggenheim Securities, LLC acted as financial advisor, and
Sullivan & Cromwell LLP and Vinson & Elkins LLP acted as
legal advisors for California Resources Corporation on the
California Carbon Management Partnership with Brookfield Renewable
deal.
Conference Call Details
To participate in the conference call scheduled for August 4,
2022, at 12:00 p.m. Eastern Time, please dial (877) 328-5505
(International calls please dial +1 (412) 317-5421) or access via
webcast at www.crc.com 15 minutes prior to the scheduled start time
to register. Participants may also pre-register for the conference
call at to https://dpregister.com/sreg/10167707/f307b93bd1. A
digital replay of the conference call will be archived for
approximately 90 days and supplemental slides for the conference
call will be available online in the Investor Relations section of
www.crc.com.
1 See Attachment 2 for the non-GAAP financial measures of
adjusted EBITDAX, operating costs per BOE (excluding effects of
PSCs), adjusted net income (loss), adjusted net income (loss) per
share - basic and diluted), free cash flow and free cash flow,
after special items including reconciliations to their most
directly comparable GAAP measure, where applicable. For the full
year 2022 estimates of the non-GAAP measures of adjusted EBITDAX
and free cash flow, including reconciliations to their most
directly comparable GAAP measure, see Attachment 7. 2 Calculated as
$324 million of cash plus $552 million of capacity on CRC's
Revolving Credit Facility less $136 million in outstanding letters
of credit. 3 2022 guidance assumes a 2022 Brent price of $103.42
per barrel of oil, NGL realizations consistent with prior years and
a NYMEX gas price of $5.62 per mcf. CRC's share of production under
PSC contracts decreases when commodity prices rise and increases
when prices fall. 4 CMB Expenses include start-up expenditures.
About California Resources
Corporation
California Resources Corporation (CRC) is an independent oil and
natural gas company committed to energy transition in the sector.
CRC has some of the lowest carbon intensity production in the US
and we are 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, HoldCo or any of their respective
subsidiaries and affiliates.
About Brookfield
Renewable
Brookfield Renewable operates one of the world’s largest
publicly traded, pure-play renewable power platforms. Its portfolio
consists of hydroelectric, wind, solar and storage facilities in
North America, South America, Europe and Asia, and totals
approximately 21,000MW of installed capacity and an approximately
69,000MW development pipeline. Investors can access its portfolio
either through Brookfield Renewable Partners L.P. (NYSE: BEP; TSX:
BEP.UN), or Brookfield Renewable Corporation (NYSE, TSX: BEPC), a
Canadian corporation. Brookfield Renewable is the flagship listed
renewable power company of Brookfield Asset Management, a leading
global alternative asset manager with approximately $725 billion of
assets under management.
The Brookfield Global Transition Fund, co-led by Mark Carney,
Brookfield Vice Chair and Head of Transition Investing, and Connor
Teskey, CEO of Brookfield Renewable, is Brookfield’s inaugural
impact fund focusing on investments that accelerate the global
transition to a net-zero carbon economy, while delivering strong
risk-adjusted returns to investors.
The Fund targets investment opportunities relating to reducing
greenhouse gas emissions and energy consumption, as well as
increasing low-carbon energy capacity and supporting sustainable
solutions. Consistent with its dual objectives of earning strong
risk-adjusted returns and generating a measurable positive
environmental change, the Fund will report to investors on both its
financial and environmental impact performance.
Forward-Looking
Statements
This document contains statements that we believe 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 we believe the expectations and forecasts reflected in
CRC's forward-looking statements are reasonable, they are
inherently subject to numerous risks and uncertainties, most of
which are difficult to predict and many of which are beyond CRC's
control. No assurance can be given that such forward-looking
statements will be correct or achieved or that the assumptions are
accurate or will not change over time. Particular uncertainties
that could cause our actual results to be materially different than
those expressed in CRC's forward-looking statements include:
- fluctuations in commodity prices and the potential for
sustained low oil, natural gas and natural gas liquids prices;
- equipment, service or labor price inflation or
unavailability;
- legislative or regulatory changes, including those related to
(i) drilling, completion, well stimulation, operation, maintenance
or abandonment of wells or facilities, (ii) managing energy, water,
land, greenhouse gases (GHGs) or other emissions, (iii) protection
of health, safety and the environment, (iv) tax credits or other
incentives, or (v) transportation, marketing and sale of our
products;
- availability or timing of, or conditions imposed on, permits
and approvals necessary for drilling or development activities and
carbon management projects;
- changes in business strategy and CRC's capital plan;
- lower-than-expected production, reserves or resources from
development projects or acquisitions, or higher-than-expected
decline rates;
- incorrect estimates of reserves and related future cash flows
and the inability to replace reserves;
- the recoverability of resources and unexpected geologic
conditions;
- CRC’s ability to utilize storage capacity of the 26R storage
reservoir consistent with the Joint Venture and Investment
Agreement through either storage only contracts or as part of an
integrated project;
- CRC’s ability to identify and develop projects that are
acceptable to the JV;
- CRC’s ability to successfully execute on the construction and
other aspects of the infrastructure projects and enter into third
party contracts on contemplated terms;
- CRC’s ability to realize all benefits contemplated by the
strategic partnership and business strategies and initiatives
related to energy transition, including CCS projects and other
renewable energy efforts;
- CRC's ability to finance and implement its CCS projects,
including the development of projects contemplated as part of the
strategic partnership with Brookfield;
- global geopolitical, socio-demographic and economic trends and
technological innovations;
- changes in our dividend policy and our ability to declare
future dividends;
- production-sharing contracts' effects on production and
operating costs;
- limitations on CRC's financial flexibility due to existing and
future debt;
- insufficient cash flow to fund planned investments, interest
payments on our debt, stock repurchases or changes to CRC's capital
plan;
- insufficient capital or liquidity unavailability of capital
markets or inability to attract potential investors;
- limitations on transportation or storage capacity and the need
to shut-in wells;
- inability to enter into desirable transactions, including
acquisitions, asset sales and joint ventures;
- joint ventures and acquisitions and CRC's ability to achieve
expected synergies;
- CRC's ability to utilize its net operating loss carryforwards
to reduce its income tax obligations;
- CRC's ability to successfully gather and verify data regarding
emissions, its environmental impacts and other initiatives;
- the compliance of various third parties with CRC's policies and
procedures and legal requirements as well as contracts CRC enters
into in connection with its climate-related initiatives;
- the effect of CRC's stock price on costs associated with
incentive compensation;
- changes in the intensity of competition in the oil and gas
industry;
- effects of hedging transactions;
- climate-related conditions and weather events;
- disruptions due to accidents, mechanical failures, power
outages, transportation or storage constraints, natural disasters,
labor difficulties, cyber-attacks or other catastrophic
events;
- pandemics, epidemics, outbreaks, or other public health events,
such as the COVID-19; and
- other factors discussed in Part I, Item 1A – Risk Factors in
CRC's Annual Report on Form 10-K and its other SEC filings
available at www.crc.com.
CRC cautions you not to place undue reliance on forward-looking
statements contained in this document, which speak only as of the
filing date, and CRC undertakes no obligation to update this
information. This document may also contain information from third
party sources. This data may involve a number of assumptions and
limitations, and we have not independently verified them and do not
warrant the accuracy or completeness of such third-party
information.
Attachment 1
SUMMARY OF RESULTS
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ and shares in millions, except per
share amounts)
2022
2022
2021
2022
2021
Statements of Operations:
Revenues
Oil, natural gas and NGL sales
$
718
$
628
$
478
$
1,346
$
910
Net loss from commodity derivatives
(100
)
(562
)
(265
)
(662
)
(478
)
Sales of purchased natural gas
75
32
48
107
146
Electricity sales
49
34
33
83
66
Other revenue
5
21
10
26
23
Total operating revenues
747
153
304
900
667
Operating Expenses
Operating costs
190
182
169
372
333
General and administrative expenses
56
48
48
104
96
Depreciation, depletion and
amortization
50
49
54
99
106
Asset impairments
2
—
—
2
3
Taxes other than on income
42
34
37
76
77
Exploration expense
1
1
2
2
4
Purchased natural gas expense
67
21
30
88
91
Electricity generation expenses
33
24
17
57
41
Transportation costs
12
12
14
24
26
Accretion expense
11
11
13
22
26
Other operating expenses, net
9
14
10
23
27
Total operating expenses
473
396
394
869
830
Net gain on asset divestitures
4
54
—
58
—
Operating Income (Loss)
278
(189
)
(90
)
89
(163
)
Non-Operating (Expenses) Income
Reorganization items, net
—
—
(2
)
—
(4
)
Interest and debt expense, net
(13
)
(13
)
(13
)
(26
)
(26
)
Net loss on early extinguishment of
debt
—
—
—
—
(2
)
Other non-operating expenses, net
1
1
(2
)
2
(1
)
Net Income (Loss) Before Income
Taxes
266
(201
)
(107
)
65
(196
)
Income tax (provision) benefit
(76
)
26
—
(50
)
—
Net income (loss)
190
(175
)
(107
)
15
(196
)
Net income attributable to noncontrolling
interests
—
—
(4
)
—
(9
)
Net Income (Loss) Attributable to
Common Stock
$
190
$
(175
)
$
(111
)
$
15
$
(205
)
Net income (loss) attributable to common
stock per share - basic
$
2.48
$
(2.23
)
$
(1.34
)
$
0.19
$
(2.46
)
Net income (loss) attributable to common
stock per share - diluted
$
2.41
$
(2.23
)
$
(1.34
)
$
0.19
$
(2.46
)
Adjusted net income
$
89
$
91
$
78
$
180
$
180
Adjusted net income per share - basic
$
1.16
$
1.16
$
0.94
$
2.32
$
2.16
Adjusted net income per share -
diluted
$
1.13
$
1.13
$
0.94
$
2.26
$
2.15
Weighted-average common shares outstanding
- basic
76.7
78.5
83.1
77.6
83.2
Weighted-average common shares outstanding
- diluted
78.8
78.5
83.1
79.6
83.2
Adjusted EBITDAX
$
204
$
206
$
169
$
410
$
358
Effective tax rate
29
%
13
%
0
%
78
%
0
%
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ in millions)
2022
2022
2021
2022
2021
Cash Flow Data:
Net cash provided by operating
activities
$
181
$
160
$
127
$
341
$
274
Net cash used in investing activities
$
(76
)
$
(53
)
$
(43
)
$
(129
)
$
(63
)
Net cash used by financing activities
$
(109
)
$
(84
)
$
(63
)
$
(193
)
$
(88
)
June 30,
December 31,
($ and shares in millions)
2022
2021
Selected Balance Sheet Data:
Total current assets
$
851
$
753
Property, plant and equipment, net
$
2,675
$
2,599
Deferred tax asset
$
367
$
396
Total current liabilities
$
1,208
$
854
Long-term debt, net
$
591
$
589
Noncurrent asset retirement
obligations
$
409
$
438
Stockholders' Equity
$
1,517
$
1,688
Outstanding shares
75.4
79.3
GAINS AND LOSSES FROM COMMODITY
DERIVATIVES
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ millions)
2022
2022
2021
2022
2021
Non-cash derivative gain (loss)
$
141
$
(381
)
$
(183
)
$
(240
)
$
(357
)
Net payments on settled commodity
derivatives
(241
)
(181
)
(82
)
(422
)
(121
)
Net loss from commodity derivatives
$
(100
)
$
(562
)
$
(265
)
$
(662
)
$
(478
)
CAPITAL INVESTMENTS
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ millions)
2022
2022
2021
2022
2021
Facilities
$
15
$
17
$
11
$
32
$
18
Drilling
62
59
28
121
41
Workovers
9
6
10
15
17
Total E&P capital
86
82
49
168
76
CMB
10
1
—
11
—
Other
2
16
1
18
1
Total capital program
$
98
$
99
$
50
$
197
$
77
Attachment 2
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
To supplement the presentation of its
financial results prepared in accordance with U.S generally
accepted accounting principles (GAAP), management uses certain
non-GAAP measures to assess its financial condition, results of
operations and cash flows. The non-GAAP measures include adjusted
net income (loss), adjusted EBITDAX, adjusted EBITDAX margin,
discretionary cash flow, free cash flow and operating costs per
BOE, among others. These measures are also widely used by the
industry, the investment community and our lenders. Although these
are non-GAAP measures, the amounts included in the calculations
were computed in accordance with GAAP. Certain items excluded from
these non-GAAP measures are significant components in understanding
and assessing our financial performance, such as our cost of
capital and tax structure, as well as the effect of acquisition and
development costs of our assets. Management believes that the
non-GAAP measures presented, when viewed in combination with its
financial and operating results prepared in accordance with GAAP,
provide a more complete understanding of the factors and trends
affecting the Company's performance. The non-GAAP measures
presented herein may not be comparable to other similarly titled
measures of other companies. Below are additional disclosures
regarding each of the non-GAAP measures reported in this press
release, including reconciliations to their most directly
comparable GAAP measure where applicable.
ADJUSTED NET INCOME (LOSS)
Adjusted net income (loss) and adjusted
net income (loss) per share are non-GAAP measures. We define
adjusted net income as net income excluding the effects of
significant transactions and events that affect earnings but vary
widely and unpredictably in nature, timing and amount. These events
may recur, even across successive reporting periods. Management
believes these non-GAAP measures provide useful information to the
industry and the investment community interested in comparing our
financial performance between periods. Reported earnings are
considered representative of management's performance over the long
term. Adjusted net income (loss) is not considered to be an
alternative to net income (loss) reported in accordance with GAAP.
The following table presents a reconciliation of the GAAP financial
measure of net income and net income attributable to common stock
per share to the non-GAAP financial measure of adjusted net income
(loss) and adjusted net income (loss) per share.
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ millions, except per share amounts)
2022
2022
2021
2022
2021
Net income (loss)
$
190
$
(175
)
$
(107
)
$
15
$
(196
)
Net income attributable to noncontrolling
interests
—
—
(4
)
—
(9
)
Net income (loss) attributable to common
stock
190
(175
)
(111
)
15
(205
)
Unusual, infrequent and other items:
Non-cash (income) loss from commodity
derivatives
(141
)
381
183
240
357
Asset impairments
2
—
—
2
3
Reorganization items, net
—
—
2
—
4
Severance and termination costs
—
—
1
—
15
Net loss on early extinguishment of
debt
—
—
—
—
2
Net gain on asset divestitures
(4
)
(54
)
—
(58
)
(2
)
Rig termination expenses
—
—
1
—
2
Other, net
2
1
2
3
4
Total unusual, infrequent and other
items
(141
)
328
189
187
385
Income tax benefit (provision) of
adjustments at effective tax rate
40
(93
)
—
(53
)
—
Valuation allowance
—
31
—
31
—
Adjusted net income attributable to common
stock
$
89
$
91
$
78
$
180
$
180
Net income (loss) attributable to common
stock per share - basic
$
2.48
$
(2.23
)
$
(1.34
)
$
0.19
$
(2.46
)
Net income (loss) attributable to common
stock per share - diluted
$
2.41
$
(2.23
)
$
(1.34
)
$
0.19
$
(2.46
)
Adjusted net income per share - basic
$
1.16
$
1.16
$
0.94
$
2.32
$
2.16
Adjusted net income per share -
diluted
$
1.13
$
1.13
$
0.94
$
2.26
$
2.15
FREE CASH FLOW
Management uses free cash flow, which is
defined by us as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of our net cash provided by operating
activities to free cash flow. We supplemented our non-GAAP measure
of free cash flow with free cash flow of our exploration and
production and corporate items (Free Cash Flow for E&P,
Corporate & Other) which we believe is a useful measure for
investors to understand the results of our core oil and gas
business. We define Free Cash Flow for E&P, Corporate &
Other as consolidated free cash flow less results attributable to
our carbon management business.
We have excluded one-time costs for
bankruptcy related fees during 2021 and 2020 as a supplemental
measure of our free cash flow.
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ millions)
2022
2022
2021
2022
2021
Net cash provided by operating
activities
$
181
$
160
$
127
$
341
$
274
Capital investments
(98
)
(99
)
(50
)
(197
)
(77
)
Free cash flow
83
61
77
144
197
One-time bankruptcy related fees
—
—
2
—
4
Free cash flow, after special items
$
83
$
61
$
79
$
144
$
201
E&P, Corporate and Other Free Cash
Flow
$
98
$
64
$
79
$
162
$
201
CMB Free Cash Flow
$
(15
)
$
(3
)
$
—
$
(18
)
$
—
ADJUSTED EBITDAX
We define Adjusted EBITDAX as earnings
before interest expense; income taxes; depreciation, depletion and
amortization; exploration expense; other unusual, infrequent and
out-of-period items; and other non-cash items. We believe this
measure provides useful information in assessing our financial
condition, results of operations and cash flows and is widely used
by the industry, the investment community and our lenders. Although
this is a non-GAAP measure, the amounts included in the calculation
were computed in accordance with GAAP. Certain items excluded from
this non-GAAP measure are significant components in understanding
and assessing our financial performance, such as our cost of
capital and tax structure, as well as depreciation, depletion and
amortization of our assets. This measure should be read in
conjunction with the information contained in our financial
statements prepared in accordance with GAAP. A version of Adjusted
EBITDAX is a material component of certain of our financial
covenants under our Revolving Credit Facility and is provided in
addition to, and not as an alternative for, income and liquidity
measures calculated in accordance with GAAP.
The following table represents a
reconciliation of the GAAP financial measures of net income and net
cash provided by operating activities to the non-GAAP financial
measure of adjusted EBITDAX. We have supplemented our non-GAAP
measures of consolidated adjusted EBITDAX with adjusted EBITDAX for
our exploration and production and corporate items (Adjusted
EBITDAX for E&P, Corporate & Other) which we believe is a
useful measure for investors to understand the results of our core
oil and gas business.. We define adjusted EBITDAX for E&P,
Corporate & Other as consolidated adjusted EBITDAX less results
attributable to our carbon management business (CMB).
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ millions, except per BOE amounts)
2022
2022
2021
2022
2021
Net income (loss)
$
190
$
(175
)
$
(107
)
$
15
$
(196
)
Interest and debt expense, net
13
13
13
26
26
Depreciation, depletion and
amortization
50
49
54
99
106
Income tax provision (benefit)
76
(26
)
—
50
—
Exploration expense
1
1
2
2
4
Unusual, infrequent and other items
(a)
(141
)
328
189
187
385
Non-cash items
Accretion expense
11
11
13
22
26
Stock-based compensation
4
4
4
8
6
Post-retirement medical and pension
—
1
1
1
1
Other non-cash items
—
—
—
—
—
Adjusted EBITDAX
$
204
$
206
$
169
$
410
$
358
Net cash used by operating activities
$
181
$
160
$
127
$
341
$
274
Cash interest
2
23
2
25
5
Cash income taxes
20
—
—
20
—
Exploration expenditures
1
1
2
2
4
Working capital changes
—
22
38
22
75
Adjusted EBITDAX
$
204
$
206
$
169
$
410
$
358
E&P, Corporate & Other Adjusted
EBITDAX
$
209
$
208
$
169
$
417
$
358
CMB Adjusted EBITDAX
$
(5
)
$
(2
)
$
—
$
(7
)
$
—
Adjusted EBITDAX per Boe
$
24.61
$
25.89
$
18.48
$
25.24
$
19.78
(a) See Adjusted Net Income (Loss)
reconciliation.
ADJUSTED GENERAL & ADMINISTRATIVE
EXPENSES
Management uses a measure called adjusted
general and administrative (G&A) expenses to provide useful
information to investors interested in comparing our costs between
periods and performance to our peers. We supplemented our non-GAAP
measure of adjusted general and administrative expenses with
adjusted general and administrative expenses of our exploration and
production and corporate items (Adjusted General &
Administrative Expenses for E&P, Corporate & Other) which
we believe is a useful measure for investors to understand the
results or our core oil and gas business. We define Adjusted
General & Administrative Expenses for E&P, Corporate &
Other as consolidated adjusted general and administrative expenses
less results attributable to our carbon management business
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ millions)
2022
2022
2021
2022
2021
General and administrative expenses
$
56
$
48
$
48
$
104
$
96
Stock-based compensation
(4
)
(4
)
(4
)
(8
)
(6
)
ERP implementation costs
(1
)
—
—
(1
)
—
Adjusted G&A expenses
$
51
$
44
$
44
$
95
$
90
E&P, Corporate and Other Adjusted
G&A expenses
$
47
$
43
$
44
$
90
$
90
CMB Adjusted G&A expenses
$
4
$
1
$
—
$
5
$
—
OPERATING COSTS PER BOE
The reporting of our PSC-type contracts
creates a difference between reported operating costs, which are
for the full field, and reported volumes, which are only our net
share, inflating the per barrel operating costs. The following
table presents operating costs after adjusting for the excess costs
attributable to PSCs.
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
($ per BOE)
2022
2022
2021
2022
2021
Energy operating costs (1)
$
6.88
$
6.68
$
4.70
$
6.78
$
4.70
Gas processing costs
0.54
0.56
0.66
0.55
0.60
Non-energy operating costs (2)
15.50
15.63
13.12
15.57
13.10
Operating costs
$
22.92
$
22.87
$
18.48
$
22.90
$
18.40
Costs attributable to PSCs
Excess energy operating costs attributable
to PSCs
$
(1.03
)
$
(0.90
)
$
(0.63
)
$
(0.96
)
$
(0.60
)
Excess non-energy operating costs
attributable to PSCs
(1.55
)
(1.40
)
(1.10
)
(1.49
)
(1.06
)
Excess costs attributable to
PSCs
$
(2.58
)
$
(2.30
)
$
(1.73
)
$
(2.45
)
$
(1.66
)
Energy operating costs, excluding effect
of PSCs (1)
$
5.85
$
5.78
$
4.07
$
5.82
$
4.10
Gas processing costs, excluding effect of
PSCs
0.54
0.56
0.66
0.55
0.60
Non-energy operating costs, excluding
effect of PSCs (2)
13.95
14.23
12.02
14.08
12.04
Operating costs, excluding effects of
PSCs
$
20.34
$
20.57
$
16.75
$
20.45
$
16.74
(1) Energy operating costs consist of
purchases of natural gas to generate electricity, purchased
electricity and internal costs to produce electricity used in our
operations.
(2) Non-energy operating costs equal total
operating costs less energy and gas processing costs. However,
non-energy operating costs include the costs of purchasing natural
gas used to generate steam for our steamfloods.
Attachment 3
PRODUCTION STATISTICS
Net
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
Oil, NGLs and Natural Gas Production
Per Day
2022
2022
2021
2022
2021
Oil (MBbl/d)
San Joaquin Basin
38
38
39
38
38
Los Angeles Basin
16
18
19
17
20
Ventura Basin
—
—
3
—
2
Total
54
56
61
55
60
NGLs (MBbl/d)
San Joaquin Basin
12
9
13
11
12
Ventura Basin
—
—
—
—
1
Total
12
9
13
11
13
Natural Gas (MMcf/d)
San Joaquin Basin
132
121
135
127
135
Los Angeles Basin
1
1
1
1
1
Ventura Basin
—
—
5
—
5
Sacramento Basin
18
19
20
18
20
Total
151
141
161
146
161
Total Production (MBoe/d)
91
88
101
90
100
Gross Operated and Net
Non-Operated
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
Oil, NGLs and Natural Gas Production
Per Day
2022
2022
2021
2022
2021
Oil (MBbl/d)
San Joaquin Basin
42
43
45
42
45
Los Angeles Basin
25
26
27
26
27
Ventura Basin
—
—
3
—
3
Total
67
69
75
68
75
NGLs (MBbl/d)
San Joaquin Basin
13
9
14
11
12
Ventura Basin
—
—
—
—
1
Total
13
9
14
11
13
Natural Gas (MMcf/d)
San Joaquin Basin
141
129
144
135
144
Los Angeles Basin
7
8
8
7
8
Ventura Basin
—
—
5
—
5
Sacramento Basin
22
23
24
23
24
Total
170
160
181
165
181
Total Production (MBoe/d)
108
105
119
106
118
Note: MBbl/d refers to thousands of
barrels per day; MMcf/d refers to millions of cubic feet per day;
MBoe/d refers to thousands of barrels of oil equivalent (Boe) per
day. Natural gas volumes have been converted to Boe based on the
equivalence of energy content of six thousand cubic feet of natural
gas to one barrel of oil. Barrels of oil equivalence does not
necessarily result in price equivalence.
Attachment 4
PRICE STATISTICS
2nd Quarter
1st Quarter
2nd Quarter
Six Months
Six Months
2022
2022
2021
2022
2021
Oil ($ per Bbl)
Realized price with derivative
settlements
$
63.17
$
60.30
$
54.10
$
61.71
$
53.91
Realized price without derivative
settlements
$
112.32
$
96.13
$
68.94
$
104.07
$
64.89
NGLs ($/Bbl)
$
68.29
$
78.63
$
44.90
$
72.57
$
46.75
Natural gas ($/Mcf)
Realized price with derivative
settlements
$
6.72
$
6.28
$
3.03
$
6.51
$
3.14
Realized price without derivative
settlements
$
6.85
$
6.28
$
3.04
$
6.58
$
3.17
Index Prices
Brent oil ($/Bbl)
$
111.79
$
97.38
$
69.02
$
104.59
$
65.06
WTI oil ($/Bbl)
$
108.41
$
94.29
$
66.07
$
101.35
$
61.96
NYMEX Henry Hub average daily price
($/MMBtu)
$
6.62
$
4.19
$
2.76
$
5.40
$
2.74
NYMEX Henry Hub average monthly settled
price ($/MMBtu)
$
7.17
$
4.95
$
2.83
$
6.06
$
2.76
Realized Prices as Percentage of Index
Prices
Oil with derivative settlements as a
percentage of Brent
57
%
62
%
78
%
59
%
83
%
Oil without derivative settlements as a
percentage of Brent
100
%
99
%
100
%
100
%
100
%
Oil with derivative settlements as a
percentage of WTI
58
%
64
%
82
%
61
%
87
%
Oil without derivative settlements as a
percentage of WTI
104
%
102
%
104
%
103
%
105
%
NGLs as a percentage of Brent
61
%
81
%
65
%
69
%
72
%
NGLs as a percentage of WTI
63
%
83
%
68
%
72
%
75
%
Natural gas with derivative settlements as
a percentage of NYMEX average daily price
102
%
150
%
110
%
121
%
115
%
Natural gas with derivative settlements as
a percentage of NYMEX average monthly settled price
94
%
127
%
107
%
107
%
114
%
Natural gas without derivative settlements
as a percentage of NYMEX average daily price
103
%
150
%
110
%
122
%
116
%
Natural gas without derivative settlements
as a percentage of NYMEX average monthly settled price
96
%
127
%
107
%
109
%
115
%
Attachment 5
SECOND QUARTER 2022 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
5
—
—
—
5
Waterflood
6
7
—
—
13
Steamflood
28
—
—
—
28
Total (1)
39
7
—
—
46
SIX MONTH 2022 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
8
—
—
—
8
Waterflood
27
14
—
—
41
Steamflood
39
—
—
—
39
Total (1)
74
14
—
—
88
(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 JUNE 30, 2022
Q3 2022
Q4 2022
Q1 2023
Q2 2023
2H 2023
2024
Sold Calls
Barrels per day
34,380
25,167
18,322
17,837
11,555
—
Weighted-average Brent price per
barrel
$
60.76
$
57.82
$
57.28
$
60.00
$
57.06
—
Swaps
Barrels per day
10,476
17,263
14,620
14,475
19,395
1,492
Weighted-average Brent price per
barrel
$
53.97
$
58.79
$
67.36
$
66.36
$
68.05
$
79.06
Net Purchased Puts 1
Barrels per day
34,380
25,167
18,322
17,837
11,555
1,724
Weighted-average Brent price per
barrel
$
65.02
$
64.47
$
76.25
$
76.25
$
76.25
$
75.00
Sold Puts
Barrels per day
4,000
1,348
—
—
—
—
Weighted-average Brent price per
barrel
$
32.00
$
32.00
—
—
—
—
1 Purchased and sold puts with the same
strike price have been netted together.
Attachment 7
2022 Estimated
TOTAL CRC GUIDANCE1
Consolidated
CMB
E&P, Corporate &
Other
Net Total Production (MBoe/d)
91 - 94
91 - 94
Net Oil Production (MBbl/d)
53 - 58
53 - 58
Operating Costs ($ millions)
$725 - $755
$725 - $755
CMB Expenses2 ($ millions)
$20 - $30
$20 - $30
Adjusted General and Administrative
Expenses ($ millions)
$185 - $200
$10 - $15
$175 - $185
Capital ($ millions)
$380 - $410
$20 - $30
$360 - $380
Adjusted EBITDAX ($ millions)
$895 - $960
($30) - ($45)
$940 - $990
Free Cash Flow ($ millions)
$365 - $450
($50) - ($75)
$440 - $500
See Attachment 2 for management's disclosure of its use of these
non-GAAP measures and how these measures provide useful information
to investors about CRC's results of operations and financial
condition. CRC has supplemented its non-GAAP measures of
consolidated adjusted EBITDAX and consolidated free cash flow with
adjusted EBITDAX for its exploration and production and corporate
items (Adjusted EBITDAX for E&P, Corporate & Other) and
free cash flow from our exploration and production and corporate
items (free cash flow from E&P, Corporate & Other) which
CRC believes are useful measures for investors to understand the
results of its core oil and gas business. CRC defines adjusted
EBITDAX for E&P, Corporate & Other as consolidated adjusted
EBITDAX less results attributable to its carbon management business
(CMB). CRC defines free cash flow from E&P, Corporate &
Other as consolidated free cash flow less results attributable to
CMB.
2022 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
Net cash provided (used) by operating
activities
$
775
$
830
$
(45
)
$
(30
)
$
820
$
860
Capital investments
(410
)
(380
)
(30
)
(20
)
(380
)
(360
)
Estimated free cash flow
$
365
$
450
$
(75
)
$
(50
)
$
440
$
500
2022 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
Net income
$
495
$
515
$
(45
)
$
(30
)
$
540
$
545
Interest and debt expense, net
50
56
50
56
Depreciation, depletion and
amortization
200
210
200
210
Exploration expense
7
10
7
10
Income taxes
232
256
232
256
Unusual, infrequent and other items
Non-cash derivative gain
(90
)
(99
)
(90
)
(99
)
Gain on asset divestitures
(58
)
(58
)
(58
)
(58
)
Other
2
4
2
4
Other non-cash items
Accretion expense
40
46
40
46
Stock-based compensation
15
18
15
18
Post-retirement medical and pension
2
2
2
2
Estimated adjusted EBITDAX
$
895
$
960
$
(45
)
$
(30
)
$
940
$
990
Net cash provided (used) by operating
activities
$
775
$
830
$
(45
)
$
(30
)
$
820
$
860
Cash interest
44
48
44
48
Cash income taxes
32
38
32
38
Exploration expenditures
7
7
7
7
Working capital changes
37
37
37
37
Estimated adjusted EBITDAX
$
895
$
960
$
(45
)
$
(30
)
$
940
$
990
2022 Estimated
Consolidated
CMB
E&P, Corporate &
Other
($ millions)
Low
High
Low
High
Low
High
General and administrative expenses
$
215
$
225
$
10
$
15
$
205
$
210
Equity-settled stock-based
compensation
(23
)
(18
)
(23
)
(18
)
ERP implementation Costs
(7
)
(7
)
(7
)
(7
)
Adjusted general and administrative
expenses
$
185
$
200
$
10
$
15
$
175
$
185
1 Current guidance assumes a 2022 Brent
price of $103.42 per barrel of oil, NGL realizations consistent
with prior years and an average daily NYMEX gas price of $5.62 per
mcf. CRC's share of production under PSCs decreases when commodity
prices rise and increases when prices decline.
2 CMB Expenses include start-up
expenditures.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20220803005785/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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