General



We are an independent oil and natural gas exploration and production company
operating properties exclusively within California. We are incorporated in
Delaware and became a publicly traded company on December 1, 2014. Except when
the context otherwise requires or where otherwise indicated, all references to
''CRC,'' the ''company,'' ''we,'' ''us'' and ''our'' refer to California
Resources Corporation and its subsidiaries.

Business Environment and Industry Outlook



Our operating results and those of the oil and gas industry as a whole are
heavily influenced by commodity prices. Oil and gas prices and differentials may
fluctuate significantly as a result of numerous market-related variables,
especially given current global geopolitical and economic conditions. These and
other factors make it impossible to predict realized prices reliably.

Prices for oil and gas products in the first quarter of 2020 and in subsequent
months have been strongly influenced by the Coronavirus Disease 2019 (COVID-19)
pandemic and by the actions of foreign producers. The COVID-19 pandemic caused
an unprecedented demand collapse related to the shelter-in-place orders, travel
restrictions and general economic uncertainty, which negatively impacted crude
oil prices. In the midst of the ongoing COVID-19 pandemic, members of the
Organization of the Petroleum Exporting Countries (OPEC and together with Russia
and other allied producing countries, OPEC+) and Russia did not extend existing
oil production cuts expiring on April 1, 2020, and Saudi Arabia and Russia
announced significant increases in crude oil production. The unprecedented dual
impact of a severe global oil demand decline due to the COVID-19 pandemic
repercussions coupled with a substantial increase in supply from Saudi Arabia
and Russia resulted in a collapse in crude oil prices.
Reduced demand caused shortages in available storage facilities globally and
required many oil and gas producers to shut in wells or curtail production. In
April 2020, oil prices continued to decline precipitously temporarily reaching
negative values for spot WTI crude. In May 2020, oil prices began to recover as
producers across the world, including OPEC, Russia, the United States and others
started cutting their production levels sharply and announced significant
capital reductions, and an easing of shelter-in-place restrictions created
partial demand recovery. However, the current futures forward curve for Brent
crude indicates that prices may continue at relatively lower prices for an
extended period of time.

We continue to closely monitor the impact of COVID-19, which negatively impacted
our business and results of operations in the first quarter of 2020. In addition
to lower average realized prices for the quarter and related negative impact to
our liquidity, the sharp drop in commodity prices at the end of the first
quarter of 2020 also resulted in an impairment charge of $1.7 billion for the
first quarter. The lower commodity prices have continued into the second quarter
and are currently expected to remain depressed for an extended period of time
based on current futures curves. The extent to which our total year operating
results will be impacted by the pandemic will depend largely on future
developments, which are highly uncertain and cannot be accurately predicted,
including new information that may emerge concerning the severity of the
pandemic and actions taken by government authorities to contain the pandemic or
actions taken by other producers in response to commodity prices movements,
among other things. See Part II, Item 1A - Risk Factors, below for further
discussion regarding the impact of the pandemic and declines in commodity
prices.

The following table presents the average daily Brent, WTI and NYMEX prices for
the three months ended March 31, 2020 and 2019 and for the months of April and
May 2020:
                                         Three months ended             Month ended      Month ended May
                                             March 31,                   April 30,             31,
                                        2020              2019              2020               2020
Brent oil ($/Bbl)                $      50.96         $     63.90     $        26.63     $        32.41
WTI oil ($/Bbl)                  $      46.17         $     54.90     $        16.70     $        28.53
NYMEX gas ($/MMBtu)              $       2.05         $      3.24     $

1.73 $ 1.76

Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units.






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Going Concern Analysis and Recent Developments



Our spin-off from Occidental Petroleum Corporation (Occidental) in December 2014
burdened us with significant debt which was used to pay a $6.0 billion cash
dividend to Occidental. Together with the activity level and payables that we
assumed from Occidental and due to Occidental's retention of a vast majority of
receivables, our debt peaked at approximately $6.8 billion in May 2015. Since
then, we have engaged in a series of assets sales, joint ventures, debt
exchanges, tenders and other financing transactions to reduce our overall debt
and improve our balance sheet. As of March 31, 2020, we had reduced outstanding
debt to approximately $4.9 billion, a substantial portion of which will mature
in 2021. Our significant indebtedness, the unprecedented impact to our financial
position resulting from the commodity price decreases due to the COVID-19
pandemic and actions of foreign producers, and the continued challenging
conditions in the credit and capital markets raise substantial doubt regarding
our ability to continue as a going concern. As discussed further below, we are
actively discussing the terms of a restructuring with our creditors and other
stakeholders with the objective of enabling us to continue operations better
positioned to capitalize on our asset base and operating capabilities. However,
there can be no assurances that we will be able to successfully restructure our
indebtedness and no assurances can be given as to what value, if any, will be
ascribed to each of our securities or what types or amounts of distributions, if
any, our various stakeholders would receive in any restructuring. Any
restructuring could result in holders of certain liabilities and/or securities,
including our common stock, receiving no distribution on account of their claims
or interest.

On February 20, 2020, we launched offers to exchange a significant portion of
our Second Lien Notes and our 5.5% Senior Notes due 2021 (2021 Notes) and 6%
Senior Notes due 2024 (2024 Notes) into interests in an entity that would hold a
term royalty interest in certain of our oil and natural gas assets or new term
loans and warrants to purchase our common stock. If the offers were fully
subscribed, we expected that the transactions would have reduced our net debt by
approximately $1 billion if successfully completed. On March 16, 2020, we
announced the termination of the offers as a result of developments in the
commodity and financial markets at that time that rendered the offers
inadvisable and impractical.

On May 15, 2020, we did not make an interest payment of approximately $4.3 million on our 2024 Notes. The indenture governing the 2024 Notes provides for a 30-day grace period and the payment was subsequently made on June 12, 2020.



On May 29, 2020, we did not pay approximately $51 million in the aggregate of
interest due under (i) our $1.3 billion credit agreement with The Bank of New
York Mellon Trust Company, N.A., as administrative agent, and certain other
lenders (2017 Credit Agreement), and (ii) our $1 billion credit agreement with
The Bank of New York Mellon Trust Company, N.A., as administrative agent, and
certain other lenders (2016 Credit Agreement). Our failure to make those
interest payments constituted events of default under our 2017 Credit Agreement
and 2016 Credit Agreement and, as a result of cross default, under our Credit
Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and certain
other lenders (2014 Revolving Credit Facility).

On June 2, 2020, we entered into forbearance agreements (Forbearance Agreements)
with (i) certain lenders of a majority of the outstanding principal amount of
the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a
majority of the outstanding principal amount of the loans under the 2016 Credit
Agreement, and (iii) certain lenders of a majority of the outstanding principal
amount of the loans under the 2017 Credit Agreement. Pursuant to the Forbearance
Agreements, the lenders who are parties to the Forbearance Agreements agreed to
forbear from exercising any remedies under the 2014 Revolving Credit Facility,
2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to
make the aforementioned interest payments, through the earlier of June 14, 2020
or an event of termination as set forth in the Forbearance Agreements. On June
12, 2020, we amended the Forbearance Agreements to extend the forbearance period
to June 30, 2020. The Forbearance Agreements include a requirement that we
maintain an aggregate book cash balance of not less than $40 million for more
than three consecutive business days.

On June 15, 2020, we did not make an interest payment of approximately $72.3
million on our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes).
The indenture governing the Second Lien Notes provides for a 30-day grace
period, which will expire on July 15, 2020. A failure to pay the interest within
the 30-day grace period would constitute an event of default under this
indenture and cross defaults under our other debt instruments and agreements.


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We are actively discussing the terms of a restructuring with our creditors and
other stakeholders with the objective of reaching an agreement before the
forbearance period under the Forbearance Agreements expires on June 30, 2020.
There can be no assurances that an agreement regarding a restructuring will be
reached by the end of the forbearance period or at all or that we will be able
to successfully restructure our indebtedness. In addition, no assurances can be
given as to what values, if any, will be ascribed to each of our securities or
what types or amounts of distributions, if any, our various stakeholders would
receive in any restructuring. Any restructuring could result in holders of
certain liabilities and/or securities, including common stock, receiving no
distribution on account of their claims or interest. See Part II, Item 1A - Risk
Factors, below for further discussion regarding risks related to our ability to
continue as a going concern.

Operations

Response to COVID-19 Pandemic and Industry Downturn

We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity.



In early March, in response to the rapid fall in commodity prices, we reduced
our 2020 capital budget to a level that maintains the mechanical integrity of
our facilities to operate them in a safe and environmentally responsible manner
and ceased all field development and growth projects. We also monetized all of
our crude oil hedges for April 2020 forward with our counterparties, except for
certain hedges held by our joint venture with Benefit Street Partners (BSP JV),
for approximately $63 million to enhance our liquidity. We shut in certain
marginal wells to reduce operating costs which curtailed average gross
production volumes by approximately 7 MBoe/d and average net production volumes
by 6 MBoe/d in May 2020. As part of our operational efficiency measures, we also
evaluated our diverse portfolio and our various production mechanisms with a
focus on wells with higher operating costs. Our teams utilized our extensive
automation controls, monitored weekly well margins, and made temporary
adjustments to our producing wells to ensure our operations aligned with the
price environment. As a result of these actions, our current operating expense
run rate is below $45 million per month compared to the first quarter average of
$64 million per month. At our current level of capital investment, we anticipate
production will continue to decline at a moderate pace through the remainder of
the year.

In early March 2020, we also implemented various measures to protect the health
of our workforce and to support the prevention of COVID-19 at our plants, rigs,
fields and administrative offices. These initiatives were in accordance with the
orders and guidance of federal, state and local authorities to mitigate the
risks of the disease, and included closing all our administrative offices and
implementing remote working for most office employees. As a result, our
management team and substantially all of our office personnel, including finance
and accounting teams, worked remotely beginning in March 2020 and continuing
into June 2020, when a phased return to the office began. In addition, on April
6, 2020, we implemented reduced work hours for nearly all of our office
employees. This temporary arrangement ended at the end of May 2020. These
reductions were made in an effort to preserve liquidity after the further
deterioration of commodity prices following the outbreak of COVID-19. Our
operational employees and contractors have been classified as an essential
critical infrastructure workforce by government authorities and continue to work
in their plant and field locations under our COVID-19 Health and Safety Plan
that includes protocols for reporting of illness, self-quarantine, hygiene,
applying social distancing to minimize close contact between workers, cleaning
or disinfection of workspaces and protection of emergency response personnel. We
have not experienced any operational slowdowns due to COVID-19 among our
workforce.

Our Operations



We conduct our operations on properties that we hold through fee interests,
mineral leases and other contractual arrangements. We are the largest private
oil and natural gas mineral acreage holder in California, with interests in 2.1
million net mineral acres, approximately 60% of which is held in fee and 17% is
held by production. Our oil and gas leases have primary terms ranging from one
to ten years. Once production commences, the leases are typically extended on
the producing acreage through the end of their producing life. As a result of
our large mineral acre position held in fee, we have the flexibility to shut in
wells while retaining our oil and gas leases which are held by production.

We also own or control a network of integrated infrastructure that complements
our operations including gas processing plants, oil and gas gathering systems,
power plants and other related assets. Our strategically located infrastructure
helps us maximize the value generated from our production.

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Our share of production and reserves from operations in the Wilmington field is
subject to contractual arrangements similar to production-sharing contracts
(PSCs) that are in effect through the economic life of the assets. Under such
contracts we are obligated to fund all capital and production costs. We record a
share of production and reserves to recover a portion of such capital and
production costs and an additional share for profit. Our portion of the
production represents volumes: (i) to recover our partners' share of capital and
production costs that we incur on their behalf, (ii) for our share of
contractually defined base production and (iii) for our share of remaining
production thereafter. We generate returns through our defined share of
production from (ii) and (iii) above. These contracts do not transfer any right
of ownership to us and reserves reported from these arrangements are based on
our economic interest as defined in the contracts. Our share of production and
reserves from these contracts decreases when product prices rise and increases
when prices decline, assuming comparable capital investment and production
costs. However, our net economic benefit is greater when product prices are
higher. These contracts represented approximately 18% of our net production for
the quarter ended March 31, 2020.

In line with industry practice for reporting PSC-type contracts, we report 100%
of operating costs under such contracts in our condensed consolidated statements
of operations as opposed to reporting only our share of those costs. We report
the proceeds from production designed to recover our partners' share of such
costs (cost recovery) in our revenues. Our reported production volumes reflect
only our share of the total volumes produced, including cost recovery, which is
less than the total volumes produced under the PSC-type contracts. This
difference in reporting full operating costs but only our net share of
production equally inflates our revenue and operating costs and has no effect on
our net results.

We own a large and geographically diverse portfolio of assets that generate the following revenue streams:



Crude Oil - We sell nearly all of our crude oil into the California refining
markets, which offer relatively favorable pricing for comparable grades relative
to other U.S. regions. Substantially all of our crude oil production is
connected, via our gathering systems, to third-party pipelines and California
refining markets and we have not encountered any issues with storage or reaching
these markets during the recent industry downturn. We do not refine or process
the crude oil we produce and do not have any significant long-term
transportation arrangements.

California is heavily reliant on imported sources of energy, with approximately
72% of oil and 90% of natural gas consumed in 2019 imported from outside the
state. Nearly all of the imported oil arrives via supertanker, mostly from
foreign locations. As a result, California refiners have typically purchased
crude oil at international waterborne-based Brent prices. We continue to receive
a premium in comparison to other comparable grades due to the demand for our
product in the state of California. We believe that the limited crude
transportation infrastructure from other parts of the U.S. into California will
continue to contribute to higher realizations than most other U.S. oil markets
for comparable grades.

Natural Gas - We sell all of our natural gas not used in our operations into the
California markets on a monthly basis at market-based index pricing. Natural gas
prices and differentials are strongly affected by local market fundamentals,
such as storage capacity and the availability of transportation capacity from
producing areas. Transportation capacity influences prices because California
imports approximately 90% of its natural gas from other states and Canada. As a
result, we typically enjoy favorable pricing relative to out-of-state producers
due to lower transportation costs on the delivery of our natural gas. Changes in
natural gas prices have a smaller impact on our operating results than changes
in oil prices as only approximately 25% of our total equivalent production
volume and even a smaller percentage of our revenue is from natural gas.

In addition to selling natural gas, we also use natural gas for our steamfloods
and power generation. As a result, the positive impact of higher natural gas
prices is partially offset by higher operating costs of our steamflood projects
and power generation, but higher prices still have a net positive effect on our
operating results due to higher revenue. Conversely, lower natural gas prices
lower the operating costs but have a net negative effect on our financial
results.

We currently have sufficient firm transportation capacity contracts to transport
our natural gas, where some capacity volumes vary by month. We sell virtually
all of our natural gas production under individually negotiated contracts using
market-based pricing on a monthly or shorter basis.


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Natural Gas Liquid (NGL) - NGL price realizations are related to the supply and
demand for the products making up these liquids. Some of them more typically
correlate to the price of oil while others are affected by natural gas prices as
well as the demand for certain chemical products for which they are used as
feedstock. In addition, infrastructure constraints and seasonality can magnify
pricing volatility.

Our earnings are also affected by the performance of our complementary
processing and power-generation assets. We process our wet gas to extract NGLs
and other natural gas byproducts. We then deliver dry gas to pipelines and
separately sell the NGLs. The efficiency with which we extract liquids from the
wet gas stream affects our operating results. Our natural gas-processing plants
also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a pipeline delivery contract to transport 6,500 barrels per
day of NGLs to market. Our contract to deliver NGLs requires us to cash settle
any shortfall between the committed quantities and volumes actually delivered.
In connection with another pipeline delivery contract that expired, we made a
one-time payment of $20 million in April 2020. We sell virtually all of our NGLs
using index-based pricing. Our NGLs are generally sold pursuant to contracts
that are renewed annually. Approximately 31% of our NGLs are sold to export
markets.

Electricity - Part of the electrical output from the Elk Hills power plant is
used by Elk Hills and other nearby fields, which reduces operating costs and
increases reliability. We sell the excess electricity generated to the grid and
a local utility. The power sold to the utility is subject to agreements through
the end of 2023, which include a monthly capacity payment plus a variable
payment based on the quantity of power purchased each month. The prices obtained
for excess power impact our earnings but generally by an insignificant amount.

Derivatives and Hedging Activities



We opportunistically seek strategic hedging transactions to help protect our
cash flow, operating margin and capital program from both the cyclical nature of
commodity prices and interest rate movements while maintaining adequate
liquidity and improving our ability to comply with our debt covenants. We can
give no assurances that our hedging programs will be adequate to accomplish our
objectives. In early March 2020, in response to the rapid fall in commodity
prices, we monetized all of our crude oil hedges in place for April 2020 forward
with our counterparties, except for certain hedges held by our BSP JV, for
approximately $63 million to enhance our liquidity. As a result, we did not have
any commodity hedges that we would benefit from after the end of the first
quarter. Unless otherwise indicated, we use the term "hedge" to describe
derivative instruments that are designed to achieve our hedging program goals,
even though they are not accounted for as cash-flow or fair-value hedges.

We respond to economic conditions by adjusting the amount and allocation of our
capital program while continuing to identify efficiencies and cost savings.
Volatility in oil prices may materially affect the quantities of oil and gas
reserves we can economically produce over the longer term. With our significant
land holdings in California, we have undertaken initiatives to unlock additional
value from our surface acreage, including pursuing renewable energy
opportunities, agricultural activities and other commercial uses.


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Development Joint Ventures

We have a number of joint ventures that have allowed us to accelerate the development of our assets which provided us with operational and financial flexibility as well as near-term production benefits. The following table summarizes the cumulative investment through March 31, 2020 by our development joint venture partners, before transaction costs:


                            Cumulative Investment through
                                    March 31, 2020
                                    (in millions)
Alpine                     $                           223
Royale                                                  17
MIRA                                                   140
BSP                                                    200
  Total Capital Investment $                           580

For more information on our development joint ventures, please see our most recent Form 10-K for the year ended December 31, 2019.

Alpine JV



In July 2019, we entered into a development agreement with Alpine Energy
Capital, LLC (Alpine). Alpine has committed to invest $320 million, which may be
increased to a total investment of $500 million subject to the mutual agreement
of the parties. The initial $320 million commitment covers multiple development
opportunities and is intended to be invested over a period of up to three years
in accordance with a 275-well development plan.

On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to
a contractual right that is triggered if the average NYMEX 12-month forward
strip price for Brent crude oil falls below $45 per barrel over a 30-trading day
period. The suspension is automatically lifted and Alpine is obligated to renew
funding at such time as the average price exceeds that threshold over any
30-trading day period. If prices remain below the threshold for over 100
consecutive trading days, the development phase may be terminated by us, subject
to agreement by Alpine.

Fixed and Variable Costs
Our production costs include (1) variable costs that fluctuate with production
levels and (2) fixed costs that typically do not vary with changes in production
levels or well counts, especially in the short term. The substantial majority of
our near-term fixed costs become variable over the longer term because we manage
them based on the field's stage of life and operating characteristics. For
example, portions of labor and material costs, energy, workovers and maintenance
expenditures correlate to well count, production and activity levels. Portions
of these same costs can be relatively fixed over the near term; however, they
are managed down as fields mature in a manner that correlates to production and
commodity price levels. A certain amount of costs for facilities, surface
support, surveillance and related maintenance can be regarded as fixed in the
early phases of a program. However, as the production from a certain area
matures, well count increases and daily per well production drops, such support
costs can be reduced and consolidated over a larger number of wells, reducing
costs per operating well. Further, many of our other costs, such as property
taxes and oilfield services, are variable and will respond to activity levels
and tend to correlate with commodity prices. As a result of the measures taken
to address the recent industry downturn, we continue to believe approximately
one-third of our operating costs are fixed over the life cycle of our fields and
the remaining two-thirds costs are variable. We actively manage our fields to
optimize production and minimize costs. When we see growth in a field, we
increase capacities and, similarly, when a field nears the end of its economic
life, we manage the costs while it remains economically viable to produce.


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Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2020 and 2019:


                                   Three months ended
                                       March 31,
                                      2020           2019
Oil (MBbl/d)
   San Joaquin Basin                47                 55
   Los Angeles Basin                26                 25
   Ventura Basin                     4                  4
     Total                          77                 84
NGLs (MBbl/d)
   San Joaquin Basin                14                 14
   Ventura Basin                     -                  1
     Total                          14                 15
Natural gas (MMcf/d)
   San Joaquin Basin               152                165
   Los Angeles Basin                 2                  2
   Ventura Basin                     6                  7
   Sacramento Basin                 23                 28
     Total                         183                202

Total Net Production (MBoe/d)      121                133

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.



For the three months ended March 31, 2020 compared to the same period in 2019,
total daily production decreased by approximately 12 MBoe/d or 9%. The decrease
in production largely represented base decline resulting from low internal
capital investment during the last 12 months. In addition, our May 2019
divestiture of a 50% working interest in certain zones within our Lost Hills
field resulted in a decrease of approximately 2 MBoe/d in 2020 compared to the
prior comparative quarter. Our PSC-type contracts positively impacted our oil
production in 2020 by over 2 MBoe/d compared to 2019.


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The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three months ended March 31, 2020 and 2019:


                                               Three months ended March 31,
                                              2020                     2019
                                      Price     Realization     Price     Realization
Oil ($ per Bbl)
Brent                                $ 50.96                  $ 63.90

Realized price without hedge         $ 50.78       100%       $ 63.30         99%
Settled hedges                          4.72                     1.96
Realized price with hedge (a)        $ 55.50       109%       $ 65.26        102%

WTI                                  $ 46.17                  $ 54.90
Realized price without hedge         $ 50.78       110%       $ 63.30        115%
Realized price with hedge            $ 55.50       120%       $ 65.26        119%

NGLs ($ per Bbl)
Realized price (% of Brent)          $ 29.28        57%       $ 42.52         67%
Realized price (% of WTI)            $ 29.28        63%       $ 42.52         77%

Natural gas
NYMEX ($/MMBtu)                      $  2.05                  $  3.24

Realized price without hedge ($/Mcf) $ 2.25 110% $ 3.43

106%


Settled hedges                          0.10                    (0.05 )

Realized price with hedge ($/Mcf) $ 2.35 115% $ 3.38

 104%


(a)    March 31, 2020 prices exclude the effect of $63 million of proceeds

received in the first quarter of 2020 from settling derivative contracts

with counterparties prior to maturity.





Oil - Brent index and realized prices were lower in the three months ended
March 31, 2020 compared to the same prior-year period due to the combination of
the supply increase caused by the Saudi-Russia price war and the severe demand
decline caused by COVID-19 that began in March 2020. During April 2020, Brent
index prices and our realizations further deteriorated to $26.63 and 79%,
respectively, and recovered slightly in May 2020 to $32.41 and 93%,
respectively.

NGLs - Prices for NGLs decreased from the same prior-year period as supply
associated with high gas-producing basins outpaced steady demand, causing lower
domestic NGL prices in the first quarter of 2020. We continue to receive premium
prices for NGLs relative to national hub prices.

Natural Gas - Our natural gas realized prices were lower in the three months
ended March 31, 2020 than the comparable period of 2019. The decrease was due to
increased nationwide natural gas production, opposite of last year's local
supply constraints, resulting in lower prices across the country, and decreased
demand resulting from the shelter-in-place order related to COVID-19 that began
in March 2020.


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