California Resources Corporation (NYSE: CRC), an independent
California-based oil and gas exploration and production company,
today reported a net loss attributable to common stock of $29
million for the third quarter of 2020, and adjusted net loss1 of
$55 million. GAAP reporting requires the accounting return from the
non-controlling interest in the Ares JV upon our emergence from
bankruptcy to be taken into account in determining earnings per
share. Accordingly, CRC reported net income of $2.20 per diluted
share for the third quarter of 2020, or adjusted net income1 of
$1.68 per diluted share. Operational and financial highlights for
the third quarter of 2020 were as follows:
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CRC third quarter 2020 earnings
highlights (Graphic: Business Wire)
Highlights
- Completed a financial restructuring and emerged from Chapter 11
bankruptcy with $535 million of net debt2 and $350 million of
liquidity3
- Reported adjusted EBITDAX1 of $103 million; adjusted EBITDAX
margin1 of 25%; net cash provided by operating activities of $48
million; and free cash flow1 of $44 million after internally funded
capital
- Delivered average net production of 106,000 barrels of oil
equivalent (BOE) per day including 64,000 barrels per day of
oil
- Optimized CRC and flattened the organization for a leaner
structure, reducing costs to enhance profitability in the current
Brent price environment
- Published third annual Sustainability Report showcasing 2030
Sustainability Goals and 2019 ESG Performance data
Todd A. Stevens, CRC's President and Chief Executive Officer,
commented, “I am proud of our team's performance as we navigated
through the recent Chapter 11 restructuring while continuing to
safely operate amidst the ongoing worldwide pandemic. I strongly
believe that our new capital structure and organizational design
provide a solid foundation to create substantial value and deliver
significant shareholder returns. We look forward to further
developing our vast portfolio while generating free cash flow,
advancing our sustainability projects and ensuring that we can
continue to provide energy to California by Californians for
decades to come.”
Mr. Stevens continued, "Given the state’s energy challenges,
maintaining responsible California production without interruption
is more important than ever. California currently imports over 70%
of the oil and 90% of the natural gas it uses daily. California
needs all of its native oil and gas for personal protective
equipment, hand sanitizer, jet fuel and bunker fuel for ships in
our ports, in addition to gasoline, diesel and many other products
essential to our quality of life."
1 See Attachment 3 for the non-GAAP financial measures of
adjusted EBITDAX, adjusted EBITDAX margin, production costs per BOE
(excluding effects of PSC-type contracts), adjusted net income
(loss) and free cash flow after internally funded capital,
including reconciliations to their most directly comparable GAAP
measure, where applicable. 2 Net debt is net of unrestricted cash
of approximately $72 million and $118 million used to cash
collateralize on an interim basis certain letters of credit that
were outstanding under CRC’s senior debtor-in-possession credit
facility at the time of our emergence. 3 Liquidity includes $72
million of unrestricted cash and approximately $278 million of
availability on our Revolving Credit Facility.
Third Quarter 2020
Results
For the third quarter of 2020, CRC reported a net loss
attributable to common stock (CRC net loss) of $29 million, or net
income of $2.20 per diluted share after accounting for a return
from the noncontrolling interest in the Ares JV, compared to a net
income attributable to common stock of $94 million, or $1.89 per
diluted share, for the same period of 2019. Adjusted net loss1 for
the third quarter of 2020 was $55 million, or adjusted net income1
of $1.68 per diluted share, compared to adjusted net income1 of $17
million, or $0.35 per diluted share, for the same period in 2019.
Third quarter 2020 adjusted net loss1 excluded unusual and
infrequent items including a net gain of $66 million from
reorganization items, $15 million of Chapter 11 transaction costs,
$10 million of severance expenses and other net charges of $15
million. Third quarter 2019 adjusted net income1 excluded a net
gain of $82 million on debt repurchases and non-cash losses on
commodity derivatives of $6 million.
Adjusted EBITDAX1 for the third quarter of 2020 was $103 million
and cash provided by operating activities was $48 million. Free
cash flow1 was $44 million after taking into account CRC's
internally funded capital of $4 million.
Total daily net production volumes decreased 17% year-over-year,
from 128,000 BOE per day for the third quarter of 2019 to 106,000
BOE per day for the third quarter of 2020. The decrease from the
same prior-year period over our mid-teens natural decline rate was
primarily due to shut-in production driven by the collapse in
commodity prices, power outages and reduced well repair work.
PSC-type contracts positively impacted our oil production by nearly
1,000 barrels per day in the third quarter of 2020 compared to the
same prior-year period. Oil volumes in the third quarter of 2020
averaged 64,000 barrels per day, NGL volumes averaged 14,000
barrels per day and natural gas volumes averaged 168 million cubic
feet per day.
Our realized crude oil prices, including the effect of settled
hedges, decreased by $26.26 per barrel from $68.41 in the third
quarter of 2019 to $42.15 per barrel in the third quarter of 2020.
Brent realized prices were lower in the three months ended
September 30, 2020 compared to the same prior-year period due to
the combination of the supply increase caused by the Saudi-Russia
price war that began earlier in the year and the continuation of
severe demand decline caused by COVID-19. In the third quarter of
2020, hedge settlements increased our realized crude oil prices by
$0.32 per barrel compared to an increase of $5.56 per barrel in the
same prior-year period. Realized NGL prices were $25.16 per barrel,
up $1.61 per barrel over the prior-year period due to improvements
in negotiated sales differentials along with stronger NGL values
relative to crude. Realized natural gas prices were $2.22 per
thousand cubic feet (Mcf) for the third quarter of 2020, $0.51 per
Mcf lower than the same prior-year period increased natural gas
production and higher inventories across the U.S. primarily due to
shelter-in-place orders related to COVID-19, partially offset by
fewer infrastructure constraints within local California markets in
2020 compared to 2019.
Production costs for the third quarter of 2020 were $141
million, compared to $221 million for the third quarter of 2019.
The decrease was primarily due to efficiencies and streamlining of
our operations, workforce reductions and reduced activity levels,
such as well repair work, in response to the current economic
environment. On a per barrel basis, for the same comparative
periods, production costs were $14.52 and $18.82, respectively.
Excluding the effect of PSC-type contracts, production costs per
BOE1 for the third quarter of 2020 and 2019 were $13.37 and $17.44,
respectively.
G&A expenses were $64 million for the third quarter of 2020,
compared to $66 million for the same prior-year period. Third
quarter G&A expenses decreased primarily due to ongoing cost
saving efforts, workforce reductions and a decline in spending
across a number of cost categories. These reductions were offset by
an increase in cash costs related to changes to our compensation
plans prior to our bankruptcy filing and higher payout on
pre-established performance metrics on the incentive portion of
these awards in the third quarter of 2020. Excluding the cost of
employee incentive awards, the 2020 third quarter G&A was $44
million, down $11 million from $55 million in the third quarter of
2019.
CRC reported taxes other than on income of $42 million for the
third quarter of 2020, consistent with the same prior-year period.
Exploration expense was $2 million for the third quarter of 2020,
$3 million less than the same prior-year period due to lower
activity.
Total internally funded capital invested during the third
quarter of 2020 was $4 million.
Nine-Month 2020 Results
For the first nine months of 2020, CRC reported a net loss
attributable to common stock (CRC net loss) of $2,096 million, or
$39.64 per diluted share after accounting for a return from the
noncontrolling interest in the Ares JV in the third quarter of
2020, compared to a net income attributable to common stock of $39
million, or $0.77 per diluted share, for the same period of 2019.
Adjusted net loss1 for the first nine months of 2020 was $265
million, or $2.57 per diluted share, compared to adjusted net
income1 of $34 million, or $0.69 per diluted share, for the same
period in 2019. The first nine months of 2020 adjusted net loss1
excluded unusual and infrequent items including $1,736 million of
asset impairments, $64 million of Chapter 11 costs, a gain of $66
million on reorganization items, net, and other net losses of $97
million. The first nine months of 2019 adjusted net income1
excluded a net gain of $108 million from debt repurchases, $99
million of non-cash derivative losses, and a net $4 million charge
related to other unusual and infrequent items.
Adjusted EBITDAX1 for the first nine months of 2020 was $373
million and cash provided by operating activities was $141 million.
Free cash flow1 was $104 million after taking into account CRC's
internally funded capital of $37 million.
Total daily net production volumes decreased 13% year-over-year,
from 130,000 BOE per day for the first nine months of 2019 to
113,000 BOE per day for the first nine months of 2020. The decrease
over the same prior-year period was primarily due to very limited
capital investment, approximately 3,000 BOE per day of average
shut-in production during the 2020 period, the Lost Hills
divestiture, lower well repair work and other factors. PSC-type
contracts positively impacted our oil production by over 2,800
barrels per day in the first nine months of 2020 compared to the
prior-year period. Oil volumes in the first nine months of 2020
averaged 70,000 barrels per day, NGL volumes averaged 14,000
barrels per day and natural gas volumes averaged 175 million cubic
feet per day.
Our realized crude oil prices, including the effect of settled
hedges, decreased by $24.89 per barrel from $68.16 in the first
nine months of 2019 to $43.27 per barrel in the first nine months
of 2020. In the first nine months of 2020, hedge settlements
increased our realized crude oil prices by $2.00 per barrel
compared to an increase of $3.13 per barrel in the same prior-year
period. Realized NGL prices were $25.17 per barrel, down $5.87 per
barrel over the prior-year period. Realized natural gas prices were
$2.05 per thousand cubic feet (Mcf) for the first nine months of
2020, $0.77 per Mcf lower than the same prior-year period.
Production costs for the first nine months of 2020 were $460
million, compared to $684 million for the first nine months of
2019. The decrease was primarily due to efficiencies and
streamlining of our operations, workforce reductions and reduced
work schedules, as well as lower activity levels, such as well
repair work, in response to the current environment. On a per
barrel basis, for the same comparative periods, production costs
were $14.85 and $19.32, respectively. Excluding the effect of
PSC-type contracts, production costs per BOE1 for the first nine
months of 2020 and 2019 were $14.03 and $17.82, respectively.
G&A expenses were $193 million for the first nine months of
2020, compared to $228 million for the same prior-year period. The
decrease was primarily attributable to cost saving efforts,
workforce reductions and a decline in spending across a number of
cost categories.
CRC reported taxes other than on income of $121 million for the
first nine months of 2020, consistent with the same prior-year
period. Exploration expense was $9 million for the first nine
months of 2020, down from $25 million in the same prior-year period
due to lower activity.
Total capital invested during the first nine months of 2020 was
$131 million. CRC internally funded $37 million. CRC's JV partners
Macquarie Infrastructure and Real Assets Inc. (MIRA) and Alpine
invested an additional $1 million and $93 million, respectively,
which are excluded from CRC's consolidated results.
Emergence and Balance Sheet
Update
Subsequent to quarter-end, CRC emerged from Chapter 11
bankruptcy with a new balance sheet. The restructuring eliminated
all pre-filing debt and the noncontrolling interests in CRC's
midstream JV. As a result, CRC's new capital structure consists of
a $1.2 billion reserve-based lending Revolving Credit Facility with
a commitment level of $540 million, $300 million of Secured Notes
and a $200 million Second Lien Term Loan. CRC has approximately $35
million drawn on the facility at emergence, net of unrestricted
cash of approximately $72 million and $118 million used to cash
collateralize on an interim basis certain letters of credit that
were outstanding under CRC’s senior debtor-in-possession credit
facility at the time of our emergence. We expect these letters of
credit will be transitioned to our new Revolving Credit Facility
and will no longer need to be cash collateralized. We believe that
our new Revolving Credit Facility provides CRC with ample liquidity
for our operations.
Upon emergence from Chapter 11 bankruptcy on October 27th, 2020,
seven new directors were appointed to the Board of Directors. Our
Board of Directors currently consists of eight directors as
follows: (i) our President and Chief Executive Officer, Todd A.
Stevens and (ii) seven non-employee directors, including Douglas E.
Brooks, Tiffany (TJ) Thom Cepak, James N. Chapman, Mark A.
McFarland, Julio M. Quintana, William B. Roby and Brian Steck.
Operational Update
In the third quarter of 2020, CRC operated no drilling rigs. The
San Joaquin basin produced 78,000 net BOE per day. The Los Angeles
basin produced 22,000 net BOE per day, the Ventura basin produced
3,000 net BOE per day and the Sacramento basin produced 3,000 net
BOE per day.
2020 Capital Budget
Given the current commodity environment, CRC continues to be
disciplined with its capital investment and will hold its
internally funded capital program to a level that maintains the
mechanical integrity of its facilities to continue to operate them
in a safe and environmentally responsible manner.
Sustainability Update
CRC remains committed to transparent reporting of our
environmental, social and governance (ESG) data which enhances our
stakeholder engagement, strengthens our performance, and further
supports our role as a dependable and dedicated energy producer in
the State of California. Accordingly, we have continued to expand
our sustainability disclosures, and have published our third annual
Sustainability Report on our website covering our accomplishments
in 2019. CRC’s 2030 Sustainability Goals and our ongoing
sustainability strategy align with the climate goals of California,
a signatory to the Paris Climate Accord, and support the state's
sustainable development by providing safe, affordable and reliable
energy that is essential for Californians. In addition, our new
Board of Directors has reaffirmed the Sustainability – Health,
Safety, Environment and Community Committee as a standing committee
of the Board.
Hedging Update as of October 31,
2020
For the fourth quarter of 2020, CRC has protected the downside
risk of approximately 39% of its volume of third quarter oil
production, with approximately 74% of the hedges being in put
spreads and put collars at an average Brent price of $44.84 and the
remainder in swaps at an average Brent price of $44.75. For the
first quarter of 2021, CRC has protected the downside risk of
approximately 38% of its third quarter oil production, with
approximately 75% of the hedges being in put spreads and put
collars at an average Brent price of $45.00 and the remainder in
swaps at an average Brent price of $44.75. For the second quarter
of 2021, CRC has protected the downside risk of approximately 23%
of its third quarter oil production, with approximately 60% of the
hedges being in put spreads and put collars at an average Brent
price of $40.00 and the remainder in swaps at an average Brent
price of $44.75. For July 2021, CRC has protected the downside risk
of approximately 22% of its third quarter oil production, with
approximately 60% of the hedges being in put spreads and put
collars at an average Brent price of $40.00 and the remainder in
swaps at an average Brent price of $44.75.
Conference Call Details
To participate in the conference call scheduled for November
5th, 2020 at 5:00 P.M. Eastern Standard Time, either dial (877)
328-5505 (International calls please dial +1 (412) 317-5421) or
access via webcast at www.crc.com, fifteen minutes prior to the
scheduled start time to register. Participants may also
pre-register for the conference call at
http://dpregister.com/10140527. 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.
About California Resources
Corporation
California Resources Corporation (CRC) is the largest oil and
natural gas exploration and production company in California. CRC
operates its world-class resource base exclusively within the State
of California, applying complementary and integrated infrastructure
to gather, process and market its production. Using advanced
technology, CRC focuses on safely and responsibly supplying
affordable energy for California by Californians.
Forward-Looking
Statements
The information included herein contains forward-looking
statements that involve risks and uncertainties that could
materially affect our expected results of operations, liquidity,
cash flows and business prospects. Such statements include those
regarding our expectations as to our future:
- financial position, liquidity, cash flows and results of
operations
- business prospects
- transactions and projects
- operating costs
- Value Creation Index (VCI) metrics, which are based on certain
estimates including future production rates, costs and commodity
prices
- operations and operational results including production,
hedging and capital investment
- budgets and maintenance capital requirements
- reserves
- type curves
- expected synergies from acquisitions and joint ventures
Actual results may differ from anticipated results, sometimes
materially, and reported results should not be considered an
indication of future performance. While we believe assumptions or
bases underlying our expectations are reasonable and make them in
good faith, they almost always vary from actual results, sometimes
materially. We also believe third-party statements we cite are
accurate but have not independently verified them and do not
warrant their accuracy or completeness. Factors (but not
necessarily all the factors) that could cause results to differ
include:
- our ability to execute our business plan post-emergence
- the volatility of commodity prices and the potential for
sustained low oil, natural gas and NGL prices
- impact of our recent emergence from bankruptcy on our business
and relationships
- debt limitations on our financial flexibility
- insufficient cash flow to fund planned investments or changes
to our capital plan
- insufficient capital or liquidity, including as a result of
lender restrictions, 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
- our ability to utilize our net operating loss carryforwards to
reduce our income tax obligations
- limitations on the liquidity of our new common stock and
volatility of its market price
- legislative or regulatory changes, including those related to
drilling, completion, well stimulation, operation, maintenance or
abandonment of wells or facilities, managing energy, water, land,
greenhouse gases or other emissions, protection of health, safety
and the environment, or transportation, marketing and sale of our
products
- joint ventures and acquisitions and our ability to achieve
expected synergies
- the recoverability of resources and unexpected geologic
conditions
- incorrect estimates of reserves and related future cash flows
and the inability to replace reserves
- changes in business strategy
- PSC effects on production and unit production costs
- effect of stock price on costs associated with incentive
compensation
- effects of hedging transactions
- equipment, service or labor price inflation or
unavailability
- availability or timing of, or conditions imposed on, permits
and approvals
- lower-than-expected production, reserves or resources from
development projects, joint ventures or acquisitions, or
higher-than-expected decline rates
- 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 coronavirus disease (COVID-19)
- factors discussed in Item 1A, Risk Factors in CRC's Annual
Report on Form 10-K and third quarter 2020 Form 10-Q available at
www.crc.com.
Words such as "anticipate," "believe," "continue," "could,"
"estimate," "expect," "goal," "intend," "likely," "may," "might,"
"plan," "potential," "project," "seek," "should," "target, "will"
or "would" and similar words that reflect the prospective nature of
events or outcomes typically identify forward-looking statements.
Any forward-looking statement speaks only as of the date on which
such statement is made, and we undertake no obligation to correct
or update any forward-looking statement, whether as a result of new
information, future events or otherwise, except as required by
applicable law.
Attachment 1
SUMMARY OF RESULTS
(DEBTOR-IN-POSSESSION: Entity Operating
Under Chapter 11)
Third Quarter
Nine Months
($ and shares in millions, except per
share amounts)
2020
2019
2020
2019
Statements of Operations:
Revenues
Oil and natural gas sales
$
312
$
541
$
987
$
1,720
Net derivative gain (loss) from commodity
contracts
—
37
75
(31
)
Other revenue
Marketing and trading revenue
50
62
109
230
Electricity sales
43
38
75
88
Other
4
3
12
17
Total revenues
409
681
1,258
2,024
Costs and Other
Production costs
141
221
460
684
General and administrative expenses
64
66
193
228
Depreciation, depletion and
amortization
89
118
296
357
Asset impairments
—
—
1,736
—
Taxes other than on income
42
42
121
119
Exploration expense
2
5
9
25
Other expenses, net
Marketing and trading costs
35
45
67
170
Electricity cost of sales
17
18
47
51
Transportation costs
10
10
31
30
Other
22
8
75
33
Total costs and other
422
533
3,035
1,697
Operating (loss) income
(13
)
148
(1,777
)
327
Non-Operating (Loss) Income
Reorganization items, net
66
—
66
—
Interest and debt expense, net
(28
)
(95
)
(200
)
(293
)
Net gain on early extinguishment of
debt
—
82
5
108
Gain on asset divestitures
—
—
—
—
Other non-operating expenses
(32
)
(8
)
(93
)
(18
)
(Loss) Income Before Income
Taxes
(7
)
127
(1,999
)
124
Income tax provision
—
—
—
Net (Loss) Income
(7
)
127
(1,999
)
124
Net income attributable to noncontrolling
interests
(22
)
(33
)
(97
)
(85
)
Net (Loss) Income Attributable to
Common Stock
$
(29
)
$
94
$
(2,096
)
$
39
Net income (loss) attributable to common
stock per share - basic 1
$
2.20
$
1.89
$
(39.64
)
$
0.78
Net income (loss) attributable to common
stock per share - diluted 1
$
2.20
$
1.89
$
(39.64
)
$
0.77
Adjusted net (loss) income
$
(55
)
$
17
$
(265
)
$
34
Adjusted net income (loss) per share -
basic 1
$
1.68
$
0.35
$
(2.57
)
$
0.70
Adjusted net income (loss) per share -
diluted 1
$
1.68
$
0.35
$
(2.57
)
$
0.69
Weighted-average common shares outstanding
- basic
49.5
49.1
49.4
48.9
Weighted-average common shares outstanding
- diluted
49.5
49.2
49.4
49.2
Adjusted EBITDAX
$
103
$
278
$
373
$
834
Effective tax rate
0
%
0
%
0
0
%
1 Net income (loss) and adjusted net
income (loss) per diluted share for the three and nine months ended
September 30, 2020 include $138 million related to the deemed
redemption of the noncontrolling interest in the Ares JV.
Third Quarter
Nine Months
($ in millions)
2020
2019
2020
2019
Cash Flow Data:
Net cash provided by operating
activities
$
48
$
268
$
141
$
540
Net cash used in investing activities
$
(1
)
$
(121
)
$
(28
)
$
(291
)
Net cash used in financing activities
$
(51
)
$
(152
)
$
(8
)
$
(244
)
September 30,
December 31,
($ and shares in millions)
2020
2019
Selected Balance Sheet Data:
Total current assets
$
420
$
491
Property, plant and equipment, net
$
4,360
$
6,352
Total current liabilities
$
1,194
$
709
Long-term debt
$
—
$
4,877
Deferred gain and issuance costs, net
$
—
$
146
Other long-term liabilities
$
727
$
720
Liabilities subject to compromise
$
4,516
$
—
Mezzanine equity
$
692
$
802
Equity
$
(2,273
)
$
(296
)
Outstanding shares
49.5
49.2
STOCK-BASED COMPENSATION
Our consolidated results of operations for
the three and nine months ended September 30, 2020 and 2019 include
the effects of long-term stock-based compensation plans under which
awards are granted annually to executives, non-executive employees
and non-employee directors that are either settled with shares of
our common stock or cash. Our equity-settled awards granted to
executives include stock options, restricted stock units and
performance stock units that either cliff vest at the end of a
three-year period or vest ratably over a three year period, some of
which are partially settled in cash. Our equity-settled awards
granted to non-employee directors are restricted stock grants that
either vest immediately or restricted stock units that cliff vest
after one year. Our cash-settled awards granted to non-executive
employees vest ratably over a three-year period.
Changes in our stock price introduce
volatility in our results of operations because we pay cash-settled
awards based on our stock price on the vesting date and accounting
rules require that we adjust our obligation for unvested awards to
the amount that would be paid using our stock price at the end of
each reporting period. Cash-settled awards, including executive
awards partially settled in cash, account for almost 60% of our
total outstanding awards. Equity-settled awards are not similarly
adjusted for changes in our stock price.
Stock-based compensation is included in
both general and administrative expenses and production costs as
shown in the table below:
Third Quarter
Nine Months
($ in millions, except per BOE
amounts)
2020
2019
2020
2019
General and administrative expenses
(G&A)
Cash-settled awards
$
(1
)
$
(2
)
$
(3
)
$
11
Equity-settled awards
2
3
6
10
Total in G&A
$
1
$
1
$
3
$
21
Total in G&A per Boe
$
0.10
$
0.09
$
0.10
$
0.59
Production costs
Cash-settled awards
$
—
$
—
$
—
$
4
Equity-settled awards
—
1
—
3
Total in production costs
$
—
$
1
$
—
$
7
Total in production costs per Boe
$
—
$
0.09
$
—
$
0.20
Total stock-based compensation expense
$
1
$
2
$
3
$
28
Total stock-based compensation expense per
Boe
$
0.10
$
0.18
$
0.10
$
0.79
DERIVATIVE GAINS AND LOSSES ON
COMMODITY CONTRACTS
Third Quarter
Nine Months
($ millions)
2020
2019
2020
2019
Non-cash derivative gain (loss) -
excluding noncontrolling interest
$
4
$
(6
)
$
(31
)
$
(99
)
Non-cash derivative (loss) gain -
noncontrolling interest
(6
)
3
1
—
Total non-cash changes
(2
)
(3
)
(30
)
(99
)
Net proceeds on settled commodity
derivatives
2
40
42
68
Net proceeds on derivative sales prior to
maturity
—
$
—
63
Net derivative gain (loss) from commodity
contracts
$
—
$
37
$
75
$
(31
)
Attachment 2
PRODUCTION STATISTICS
Third Quarter
Nine Months
Net Oil, NGLs and Natural Gas
Production Per Day
2020
2019
2020
2019
Oil (MBbl/d)
San Joaquin Basin
40
51
42
53
Los Angeles Basin
22
24
25
24
Ventura Basin
2
4
3
4
Total
64
79
70
81
NGLs (MBbl/d)
San Joaquin Basin
14
16
14
15
Ventura Basin
—
—
—
1
Total
14
16
14
16
Natural Gas (MMcf/d)
San Joaquin Basin
142
162
148
163
Los Angeles Basin
2
2
2
2
Ventura Basin
4
4
4
6
Sacramento Basin
20
28
21
29
Total
168
196
175
200
Total Production (MBoe/d)
106
128
113
130
Third Quarter
Nine Months
Gross Operated and Net Non-Operated
Oil, NGLs and Natural Gas Production Per Day
2020
2019
2020
2019
Oil (MBbl/d)
San Joaquin Basin
46
55
49
56
Los Angeles Basin
28
32
30
33
Ventura Basin
3
5
3
5
Total
77
92
82
94
NGLs (MBbl/d)
San Joaquin Basin
14
16
14
15
Ventura Basin
—
—
—
1
Total
14
16
14
16
Natural Gas (MMcf/d)
San Joaquin Basin
153
164
157
165
Los Angeles Basin
8
9
9
9
Ventura Basin
4
4
5
6
Sacramento Basin
25
38
27
39
Total
190
215
198
219
Total Production (MBoe/d)
123
144
130
146
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 3
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
Our results of operations, which are
presented in accordance with U.S. generally accepted accounting
principles (GAAP), can include the effects of unusual,
out-of-period and infrequent transactions and events affecting
earnings that vary widely and unpredictably (in particular certain
non-cash items such as derivative gains and losses) in nature,
timing, amount and frequency. Therefore, management uses certain
non-GAAP measures to assess our financial condition, results of
operations and cash flows. These measures are 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 historic cost of
depreciable and depletable assets. These measures should be read in
conjunction with the information contained in our financial
statements prepared in accordance with GAAP.
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)
Management uses a measure called adjusted
net income (loss) to provide useful information to investors
interested in comparing our core operations between periods and our
performance to our peers. This measure is not meant to disassociate
the effects of unusual, out-of-period and infrequent items
affecting earnings from management's performance but rather is
meant to provide useful information to investors 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 (loss) attributable to common stock
to the non-GAAP financial measure of adjusted net income and
presents the GAAP financial measure of net income (loss)
attributable to common stock per diluted share and the non-GAAP
financial measure of adjusted net income per diluted share.
Third Quarter
Nine Months
($ millions, except per share amounts)
2020
2019
2020
2019
Net (loss) income
$
(7
)
$
127
$
(1,999
)
$
124
Net income attributable to noncontrolling
interests
(22
)
(33
)
(97
)
(85
)
Net (loss) income attributable to common
stock
(29
)
94
(2,096
)
39
Unusual, infrequent and other items:
Non-cash derivative (gain) loss from
commodities, excluding noncontrolling interest
(4
)
6
31
99
Asset impairments
—
—
1,736
—
Reorganization items, net
(66
)
—
(66
)
—
Severance and termination benefits
10
—
10
2
Incentive / retention award
modifications
—
—
4
—
Net gain on early extinguishment of
debt
—
(82
)
(5
)
(108
)
Chapter 11 transaction costs
15
—
64
—
NGL pipeline delivery contract payment
—
—
20
—
Power plant maintenance
—
—
7
—
Write-off of deferred financing costs
4
—
4
Other, net
15
(1
)
26
2
Total unusual, infrequent and other
items
(26
)
(77
)
1,831
(5
)
Adjusted net (loss) income
$
(55
)
$
17
$
(265
)
$
34
Net income (loss) attributable to common
stock per share - diluted 1
$
2.20
$
1.89
$
(39.64
)
$
0.77
Adjusted net income (loss) per share -
diluted 1
$
1.68
$
0.35
$
(2.57
)
$
0.69
1 Net income (loss) and adjusted net
income (loss) per diluted share for the three and nine months ended
September 30, 2020 include $138 million related to the deemed
redemption of the noncontrolling interest in the Ares JV.
FREE CASH FLOW
Management uses free cash flow, which is
defined by us as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of our net cash provided by operating
activities to free cash flow.
Third Quarter
Nine Months
($ millions)
2020
2019
2020
2019
Net cash provided by operating
activities
$
48
$
268
$
141
$
540
Capital investments
(4
)
(122
)
(37
)
(393
)
Free cash flow
44
146
104
147
BSP funded capital
—
5
—
48
Free cash flow, after internally funded
capital
$
44
$
151
$
104
$
195
ADJUSTED EBITDAX
We define adjusted EBITDAX as earnings
before interest expense; income taxes; depreciation, depletion and
amortization; exploration expense; other unusual, out-of-period and
infrequent items; and other non-cash items. Management uses
adjusted EBITDAX as a measure of operating cash flow without
working capital adjustments. A version of adjusted EBITDAX is a
material component of certain of our financial covenants under our
2014 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 presents a
reconciliation of the GAAP financial measures of net income (loss)
and net cash provided by operating activities to the non-GAAP
financial measure of adjusted EBITDAX.
Third Quarter
Nine Months
($ millions, except per BOE amounts)
2020
2019
2020
2019
Net (loss) income
$
(7
)
$
127
$
(1,999
)
$
124
Interest and debt expense, net
28
95
200
293
Depreciation, depletion and
amortization
89
118
296
357
Exploration expense
2
5
9
25
Unusual, infrequent and other items
(a)
(26
)
(77
)
1,831
(5
)
Other non-cash items
17
10
36
40
Adjusted EBITDAX
$
103
$
278
$
373
$
834
Net cash provided by operating
activities
$
48
$
268
$
141
$
540
Cash interest
21
75
80
300
Exploration expenditures
2
5
9
15
Working capital changes
32
(70
)
143
(21
)
Adjusted EBITDAX
$
103
$
278
$
373
$
834
Adjusted EBITDAX per Boe
$
10.61
$
23.68
$
12.04
$
23.55
(a) See Adjusted Net Income
reconciliation.
DISCRETIONARY CASH FLOW
We define discretionary cash flow as the
cash available after distributions to noncontrolling interest
holders and cash interest, excluding the effect of working capital
changes but before our internal capital investment. Management uses
discretionary cash flow as a measure of the availability of cash to
reduce debt or fund investments.
Third Quarter
Nine Months
($ millions)
2020
2019
2020
2019
Adjusted EBITDAX
$
103
$
278
$
373
$
834
Cash interest
(21
)
(75
)
(80
)
(300
)
Distributions paid to noncontrolling
interest holders:
BSP
(5
)
(30
)
(34
)
(55
)
Ares
(22
)
(20
)
(61
)
(60
)
Discretionary cash flow
$
55
$
153
$
198
$
419
ADJUSTED EBITDAX MARGIN
Management uses adjusted EBITDAX margin as
a measure of profitability between periods and this measure is
generally used by analysts for comparative purposes within the
industry.
Third Quarter
Nine Months
($ millions)
2020
2019
2020
2019
Total revenues
$
409
$
681
$
1,258
$
2,024
Non-cash derivative loss
2
3
30
99
Revenues, excluding non-cash derivative
gains and losses
$
411
$
684
$
1,288
$
2,123
Adjusted EBITDAX margin
25
%
41
%
29
%
39
%
PRODUCTION COSTS PER BOE
The reporting of our PSC-type contracts
creates a difference between reported production costs, which are
for the full field, and reported volumes, which are only our net
share, inflating the per barrel production costs. The following
table presents production costs after adjusting for the excess
costs attributable to PSC-type contracts.
Third Quarter
Nine Months
($ per Boe)
2020
2019
2020
2019
Production costs
$
14.52
$
18.82
$
14.85
$
19.32
Excess costs attributable to PSC-type
contracts
(1.15
)
(1.38
)
(0.82
)
(1.50
)
Production costs, excluding effects of
PSC-type contracts
$
13.37
$
17.44
$
14.03
$
17.82
Attachment 4
CAPITAL INVESTMENTS
Third Quarter
Nine Months
($ millions)
2020
2019
2020
2019
Internally funded capital
$
4
$
117
$
37
$
345
BSP funded capital
—
5
—
48
Capital investments - as reported
$
4
$
122
$
37
$
393
MIRA funded capital
—
3
1
10
Alpine funded capital
(4
)
63
93
63
Total capital program
$
—
$
188
$
131
$
466
Attachment 5
PRICE STATISTICS
Third Quarter
Nine Months
2020
2019
2020
2019
Realized Prices
Oil with hedge ($/Bbl)
$
42.15
$
68.41
$
43.27
$
68.16
Oil without hedge ($/Bbl)
$
41.83
$
62.85
$
41.27
$
65.03
NGLs ($/Bbl)
$
25.16
$
23.55
$
25.17
$
31.04
Natural gas ($/Mcf)
$
2.22
$
2.73
$
2.05
$
2.82
Index Prices
Brent oil ($/Bbl)
$
43.37
$
62.00
$
42.53
$
64.74
WTI oil ($/Bbl)
$
40.93
$
56.45
$
38.32
$
57.06
NYMEX gas ($/MMBtu)
$
1.93
$
2.27
$
1.92
$
2.72
Realized Prices as Percentage of Index
Prices
Oil with hedge as a percentage of
Brent
97
%
110
%
102
%
105
%
Oil without hedge as a percentage of
Brent
96
%
101
%
97
%
100
%
Oil with hedge as a percentage of WTI
103
%
121
%
113
%
119
%
Oil without hedge as a percentage of
WTI
102
%
111
%
108
%
114
%
NGLs as a percentage of Brent
58
%
38
%
59
%
48
%
NGLs as a percentage of WTI
61
%
42
%
66
%
54
%
Natural gas as a percentage of NYMEX
115
%
120
%
107
%
104
%
Attachment 6
NINE MONTHS 2020 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
48
—
—
—
48
Waterflood
2
4
—
—
6
Steamflood
—
—
—
—
—
Unconventional
18
—
—
—
18
Total
68
4
—
—
72
Total (a)
68
4
—
—
72
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
CRC
3
4
—
—
7
Alpine
65
—
—
—
65
Total (a)
68
4
—
—
72
There were no wells drilled in the third
quarter of 2020.
(a) Includes steam injectors and drilled
but uncompleted wells, which would not be included in the SEC
definition of wells drilled.
Attachment 7
HEDGES - AS OF OCTOBER 31, 2020
Q4 2020
Q1 2021
Q2 2021
July 2021
Sold Calls:
Barrels per day
4,800
4,500
4,500
4,200
Weighted-average price per barrel
$48.05
$48.05
$48.05
$48.05
Purchased Puts:
Barrels per day
18,600
18,000
9,000
8,400
Weighted-average price per barrel
$44.84
$45.00
$40.00
$40.00
Sold Puts:
Barrels per day
13,800
13,500
4,500
4,200
Weighted-average price per barrel
$36.52
$36.67
$30.00
$30.00
Swaps:
Barrels per day
6,400
6,000
6,000
5,600
Weighted-average price per barrel
$44.75
$44.75
$44.75
$44.75
The outcomes of the derivative positions
are as follows:
Sold calls - we make settlement payments
for prices above the indicated weighted-average price per
barrel
Purchased puts - we receive settlement
payments for prices below the indicated weighted-average price per
barrel
Sold puts - we make settlement payments
for prices below the indicated weighted-average price per
barrel
The BSP JV holds crude oil derivatives and
natural gas swaps for insignificant volumes through 2021 that are
included in our consolidated results. The hedges entered into by
the BSP JV could affect the timing of the redemption of BSP's
preferred interest.
Attachment 8
EARNINGS PER SHARE
Three Months Ended
Nine Months Ended
September 30,
September 30
In millions, except per-share amounts
2020
2019
2020
2019
Basic EPS calculation
Net (loss) income
$
(7
)
$
127
$
(1,999
)
$
124
Less: net income attributable to
noncontrolling interests
(22
)
(33
)
(97
)
(85
)
Net (loss) income attributable to common
stock
(29
)
94
(2,096
)
39
Adjustments:
Net income allocated to participating
securities
—
(1
)
—
(1
)
Return from noncontrolling interest
holders (a)
138
—
138
—
Net income (loss) available to common
shares
109
93
(1,958
)
38
Weighted-average common shares outstanding
- basic
49.5
49.1
49.4
48.9
Basic EPS
$
2.20
$
1.89
$
(39.64
)
$
0.78
Diluted EPS calculation
Net (loss) income
$
(7
)
$
127
$
(1,999
)
$
124
Less: net income attributable to
noncontrolling interests
(22
)
(33
)
(97
)
(85
)
Net (loss) income attributable to common
stock
(29
)
94
(2,096
)
39
Adjustments:
Net income allocated to participating
securities
—
(1
)
—
(1
)
Return from noncontrolling interest
holders (a)
138
—
138
—
Net income (loss) available to common
shares
109
93
(1,958
)
38
Weighted-average common shares outstanding
- basic
49.5
49.1
49.4
48.9
Dilutive effect of potentially dilutive
securities
—
0.1
—
0.3
Weighted-average common shares outstanding
- diluted
49.5
49.2
49.4
49.2
Diluted EPS
$
2.20
$
1.89
$
(39.64
)
$
0.77
Weighted-average anti-dilutive shares
3.3
3.2
4.4
2.3
(a) Return from noncontrolling interest
holders relates to the deemed redemption of the noncontrolling
interests in the Ares JV.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20201105006181/en/
Scott Espenshade (Investor Relations) 818-661-6010 Scott.Espenshade@crc.com
Margita Thompson (Media) 818-661-6005
Margita.Thompson@crc.com
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