General

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.



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. On July 15,
2020, we filed voluntary petitions in the United States Bankruptcy Court for the
Southern District of Texas seeking relief under Chapter 11 of Title 11 of the
United States Bankruptcy Code and on October 27, 2020 we emerged from the
Chapter 11 proceedings as further described below.

Our condensed consolidated financial statements, including the Notes thereto,
included in Part I, Item - Financial Statements have been prepared assuming we
will continue as a going concern. We have applied Financial Accounting Standards
Board Accounting Standards Codification 852, Reorganizations (ASC 852), in
preparing these unaudited condensed consolidated financial statements. ASC 852
requires that the financial statements, for periods subsequent to the petition
date (July 15, 2020), distinguish transactions and events that are directly
associated with the reorganization from the ongoing operations of the business.
As a result, we have segregated liabilities and obligations whose treatment and
satisfaction are dependent on the outcome of the Chapter 11 Cases and classified
these items as liabilities subject to compromise (LSTC) on our condensed
consolidated balance sheet as of September 30, 2020. In addition, we have
classified all income, expenses, gains or losses that were incurred or realized
as a result of the Chapter 11 Cases subsequent to the petition date as
reorganization items, net in our condensed consolidated statement of operations
for the period ended September 30, 2020.

Further, we believe that we are required to adopt fresh start accounting upon
emergence from bankruptcy because (1) the holders of existing voting shares
prior to emergence received less than 50% of our new voting shares following our
emergence from bankruptcy and (2) the reorganization value of our assets
immediately prior to the confirmation of the Plan was less than the
post-petition liabilities and allowed claims, which are included in liabilities
subject to compromise. Fresh start accounting will be applied as of October 27,
2020, the date we emerged from bankruptcy. Under the principles of fresh start
accounting, a new reporting entity is considered to have been created, and, as a
result, the reorganization value of the emerging entity is assigned to
individual assets and liabilities based on their estimated relative fair values.
The process of estimating the fair value of our assets, liabilities and equity
upon emergence is currently ongoing. In support of the Plan, the enterprise
value of the successor company was estimated and approved by the Bankruptcy
Court to be in the range of $2.2 billion to $2.8 billion. As a result of the
application of fresh start accounting and the effects of the implementation of
the Plan, the financial statements of the successor entity will not be
comparable to the financial statements, including this statement, prepared prior
to our Effective Date.

Chapter 11 Proceedings

Our spin-off from Occidental Petroleum Corporation (Occidental) on November 30,
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 the vast majority
of our receivables, our debt peaked at approximately $6.8 billion in May 2015.
Since then, we have engaged in a series of asset sales, joint ventures, debt
exchanges, tenders, debt repurchases and other financing transactions to reduce
our overall level of debt and improve our balance sheet prior to filing for
bankruptcy. As of September 30, 2020, we had outstanding net long-term debt of
approximately $5.1 billion, of which $4.4 billion is presented as liabilities
subject to compromise on our condensed consolidated balance sheet.

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of
Title 11 of the Bankruptcy Code (Chapter 11 Cases) in the United States
Bankruptcy Court for the Southern District of Texas, Houston Division
(Bankruptcy Court). The Chapter 11 Cases were jointly administered under the
caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ).
We filed with the Bankruptcy Court, on July 24, 2020, the Debtors' Joint Plan of
Reorganization under Chapter 11 of the Bankruptcy Code and, on October 8, 2020,
the Amended Debtors' Joint Plan of Reorganization Under Chapter 11 of the
Bankruptcy Code (as amended, supplemented or modified, the Plan). On October 13,
2020, the Bankruptcy Court confirmed the Plan, which was conditioned on certain
items such as obtaining exit financing. The conditions to effectiveness of the
Plan were satisfied and we emerged from Chapter 11 on October 27, 2020
(Effective Date).
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During the course of the Chapter 11 Cases, the Bankruptcy Court granted the
relief requested in certain motions, authorizing payments of pre-petition
liabilities with respect to certain employee compensation and benefits, taxes,
royalties, certain essential vendor payments and insurance and surety
obligations, which allowed our business operations to continue uninterrupted
during the pendency of the Chapter 11 Cases. All transactions outside the
ordinary course of business required the prior approval of the Bankruptcy Court.

On July 15, 2020, immediately prior to the commencement of the Chapter 11 Cases,
we and certain affiliates of Ares Management L.P. (Ares), including ECR
Corporate Holdings L.P., a portfolio company of Ares (ECR), entered into a
Settlement and Assumption Agreement (Settlement Agreement) related to our
midstream joint venture, Elk Hills Power, LLC (Ares JV or Elk Hills Power),
which holds our Elk Hills power plant and a cryogenic gas processing plant. On
August 25, 2020, the Bankruptcy Court entered an order approving the Settlement
Agreement on a final basis. Among other things, the Settlement Agreement
included a conversion right, which would be deemed exercised upon our emergence
from bankruptcy, allowing us to acquire all (but not less than all) of the
equity interests in the Ares JV held by ECR in exchange for secured notes (EHP
Notes), approximately 20.8% of our new common stock (Ares Settlement Stock) and
$2.5 million in cash. For more information on the Settlement Agreement, see Part
I, Item 1 - Financial Statements, Note 7 Joint Ventures.

The commencement of the Chapter 11 Cases constituted an event of default that
accelerated our obligations under the following agreements: (i) Credit
Agreement, dated as of September 24, 2014, among JPMorgan Chase Bank, N.A., as
administrative agent, and the lenders that are party thereto (2014 Revolving
Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The
Bank of New York Mellon Trust Company, N.A., as collateral and administrative
agent, and the lenders that are party thereto (2016 Credit Agreement), (iii)
Credit Agreement, dated as of November 17, 2017, among The Bank of New York
Mellon Trust Company, N.A., as administrative agent, and the lenders that are
party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8%
Senior Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes
due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes and together with
the 5% Senior Notes due 2020 and 2021 Notes, the Senior Notes). Additionally,
other events of default, including cross-defaults, are present under these debt
agreements. Under the Bankruptcy Code, the creditors under these debt agreements
were stayed from taking any action against us, including exercising remedies as
a result of any event of default. See Part I, Item 1 - Financial Statements,
Note 6 Debt for additional details about our debt.

Joint Plan of Reorganization Under Chapter 11

Pursuant to the Plan, the following transactions occurred on the Effective Date:



•We issued an aggregate of 83.3 million shares of new common stock and reserved
4.4 million shares for issuance upon exercise of the warrants described below;
•We acquired all of the member interests in the Ares JV held by ECR in exchange
for the EHP Notes, 17.3 million shares of new common stock and $2.5 million in
cash (see Part I, Item 1 - Financial Statements, Note 6 Debt and Part I, Item 1
- Financial Statements, Note 7 Joint Ventures for additional information);
•Holders of secured claims under the 2017 Credit Agreement received 22.7 million
shares of new common stock in exchange for those claims, and holders of
deficiency claims under the 2017 Credit Agreement and all outstanding
obligations under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and
2024 Notes received 4.4 million shares of new common stock in exchange for those
claims;
•In connection with the Subscription Rights offering and Backstop Commitment
Agreement, 34.6 million shares of new common stock were issued in exchange for
$446 million (net of a $4 million fee), the proceeds of which were used to pay
down our debtor-in-possession financing;
•Our Subscription Rights offering was backstopped by certain creditors who
received 3.5 million shares of new common stock as a backstop commitment premium
(refer to Part I, Item 1 - Financial Statements, Note 16 Equity for additional
information on the backstop commitment premium);
•The holders of Unsecured Debt Claims (as defined in the Plan) under the 2016
Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received Tier 1
Warrants and Tier 2 Warrants (each as defined in the Plan and collectively,
Warrants) to purchase up to 2% and 3%, respectively, of our outstanding shares
(on a fully diluted basis calculated immediately after the Effective Date), with
an initial exercise price of $36.00 per share, which expire on October 27, 2024
and have customary anti-dilution protections (refer to Note 16 Equity for
additional information on the Warrants);
•All other general unsecured claims will be paid or disputed in the ordinary
course of business; and
•All existing equity interests were cancelled and their holders received no
distributions.
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As a condition to our emergence, we repaid the outstanding balance of our
debtor-in-possession financing with proceeds from our Subscription Rights
offering, Backstop Commitment Agreement and a new senior secured revolving
credit facility led by Citibank, N.A. We also issued approximately 821,000
shares of new common stock for a junior debtor-in-possession exit fee. For more
information on our debtor-in-possession credit agreements and our post-emergence
indebtedness, see Part I, Item 1 - Financial Statements, Note 6 Debt.

Additionally, pursuant to our Plan, our post-emergence Board of Directors
consists of nine directors as follows: (i) our President and Chief Executive
Officer, Todd A. Stevens, (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, and (iii) one vacancy which will
be filled by our post-emergence Board of Directors in accordance with our
charter and bylaws. The seven non-employee directors were all appointed to the
Board of Directors on October 27, 2020.

Our Board of Directors has determined that Ms. Cepak and Messrs. Brooks,
Chapman, McFarland, Quintana, Roby and Steck are independent directors as that
term is defined in the listing standards of the New York Stock Exchange (NYSE).
Mr. Stevens is not considered by our Board of Directors to be independent
because of his current employment with CRC.

Changes to our Stock-Based Compensation Programs



As a result of our bankruptcy, the outstanding stock-based awards under our
Amended and Restated California Resources Corporation Long-Term Incentive Plan
were cancelled on our Effective Date. Any new stock-based awards or compensation
plans will be reviewed and approved by our Board of Directors, which includes
seven new directors appointed on October 27, 2020.

The cancellation of these stock-based compensation awards resulted in the recognition of all previously unrecognized compensation expense for equity-settled awards and the liability related to our cash-settled awards was eliminated as the participants received no consideration. The net effect of these adjustments was not material to our financial statements.

Changes to the 2020 Compensation Programs in Second Quarter 2020



In the second quarter of 2020, resulting from the unprecedented circumstances
affecting the industry and market volatility, we reviewed our incentive programs
for the entire workforce to determine whether those programs appropriately
aligned compensation opportunities with our 2020 goals and ensured the stability
of our workforce. Following this review, effective May 19, 2020, our then Board
of Directors approved changes in the variable compensation programs for all
participating employees. The previously established target amounts of 2020
variable compensation programs did not change; however, all amounts that vest
are being settled in cash. As a condition to receiving any award, participants
waived participation in our 2020 annual incentive program and forfeited all
stock-based compensation awards previously granted in 2020. At that time, there
were no changes to stock-based compensation awards granted prior to February
2020; however, these pre-2020 awards were subsequently cancelled as part of the
Plan. Changes to the variable compensation programs had the effect of
accelerating the associated payments into 2020 from future periods. However, the
total amount of compensation to be paid under the variable compensation programs
at target for 2020 remained largely the same as the amounts that would have been
paid at target prior to the changes. Our future compensation programs will be
determined by our new Board of Directors.

Organizational Changes



During the course of the Chapter 11 Cases, we evaluated the structure of our
workforce and, in August 2020, we implemented organizational changes that
resulted in a reduction of our headcount from 1,250 to approximately 1,100
employees. We believe the steps taken improved and strengthened our business as
we emerge from bankruptcy. We recorded a one-time $10 million restructuring
charge in the third quarter of 2020. We will continue to evaluate resource
levels depending on commodity prices.

Business Environment and Industry Outlook


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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 2020 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 due to
global shelter-in-place orders, travel restrictions and general economic
uncertainty, which negatively impacted crude oil prices. In addition, members of
the Organization of the Petroleum Exporting Countries (OPEC) and Russia agreed
to carry out record oil production cuts in April 2020 to be followed by gradual
incremental increases in multiple steps. In the summer of 2020, OPEC and Russia
moved ahead with the first hike in crude oil output. The next hike in crude oil
output is currently scheduled for January 2021. As a result of these conditions,
the Brent oil price has been trading in a narrow range around $40 per barrel for
several months.
Reduced demand initially 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 declined precipitously, temporarily
reaching negative values for spot West Texas Intermediate (WTI) crude. From May
2020 through August 2020, oil prices began to recover as inventory levels
stabilized and an easing of shelter-in-place restrictions created partial demand
recovery. Prices declined again slightly in September 2020 as demand for oil
dropped due to an increase in COVID-19 cases around the world. Demand and
pricing may decline again due to a resurgence in the number of cases globally
and across parts of the United States, which could result in the re-imposition
of certain restrictions. The current futures forward curve for Brent crude
indicates that prices may continue at close to current levels, which are
significantly lower than pre-pandemic levels, 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 beginning in the first quarter of 2020.
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 potential vaccines, a resurgence of the pandemic and actions taken to
contain it or actions taken by government authorities or other producers in
response to commodity price 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 and nine months ended September 30, 2020 and 2019:


                           Three months ended                 Nine months ended
                              September 30,                     September 30,
                            2020            2019              2020          2019
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

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


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In response to the rapid fall in commodity prices in March 2020, 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. As a result, our internally
funded capital was $7 million in the second and third quarters of 2020. We also
monetized all of our crude oil hedges in March 2020, except for certain hedges
held by our joint venture with Benefit Street Partners (BSP JV), for
approximately $63 million to enhance our liquidity. We began shutting in high
cost, negative margin wells in March 2020 to reduce operating costs and enhance
cash flow which curtailed average net production volumes by approximately 5
MBoe/d and 3 MBoe/d for the second and third quarters of 2020, respectively. As
part of our operational efficiency measures, we 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, as well as further cost rationalization and streamlining efforts
coupled with lower activity levels, our third quarter 2020 average operating
expense run rate is below $50 million per month compared to the first quarter of
2020 average of $64 million per month. At our current level of capital
investment and surface activity levels, production could continue to decline at
a moderate pace through the remainder of the year.

We have 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 temporarily 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 worked remotely
beginning in March 2020. In June 2020, we began a phased return to the office,
focused on those employees for whom remote work was not feasible. In addition,
in April 2020, we implemented reduced work hours for nearly all of our office
employees and reduced salaries for our management team, in each case on a
temporary basis that ended in May 2020. In August 2020, we implemented
organizational and operational efficiencies that resulted in a reduction of our
headcount to approximately 1,100 employees. These actions were made in an effort
to preserve liquidity after the deterioration of commodity prices following the
outbreak of COVID-19. Our operational employees and contractors and certain
support personnel have been classified as an essential critical infrastructure
workforce by government authorities. Accordingly, they worked through the
shutdowns and continue to work in their plant, rig, field and office 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
non-governmental 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 generally
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.

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 obtain additional
value from our surface acreage, including pursuing carbon capture and
sequestration, renewable energy opportunities, agricultural activities and other
commercial uses.

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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 17% of our net production for
the three months ended September 30, 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 and general and administrative costs but
only our net share of production equally inflates our revenue, general and
administrative 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 significant issues with storage
or reaching these markets during the 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 we assumed from
Occidental, we made a one-time deficiency payment of $20 million in April 2020
when the contract expired. We sell virtually all of our NGLs using index-based
pricing. Our NGLs are generally sold pursuant to contracts that are renewed
annually. Approximately 33% 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 a local
utility, other third parties and the grid. 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. Any excess capacity not sold to other third parties is sold to the grid.
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 assurance that our hedging programs will be adequate to accomplish our
objectives.

The Senior DIP Credit Agreement required us to enter into hedging arrangements
covering at least 25% of our share of expected crude oil production for the next
twelve months. On July 24, 2020, we entered into various derivative instruments
to satisfy this requirement. Our post-emergence Revolving Credit Facility and
Second Lien Term Loan require us to maintain hedges on a higher amount of crude
oil production as described in Part I, Item 1 - Financial Statements, Note 6
Debt.

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.

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 September 30, 2020 by our development joint venture partners, before transaction costs:


                               Cumulative Investment through
                                     September 30, 2020
                                       (in millions)
Alpine                        $                          227
Royale                                                    17
MIRA                                                     139
BSP                                                      200
  Total Capital Investment    $                          583



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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 may be lifted by mutual consent. As of September 30,
2020, funding for the initial development phase has not re-started.

Midstream Joint Venture

Ares JV



In February 2018, our wholly-owned subsidiary California Resources Elk Hills,
LLC (CREH) entered into a midstream JV with ECR, a portfolio company of Ares.
The Ares JV holds the Elk Hills power plant (a 550-megawatt natural gas fired
power plant) and a 200 MMcf/d cryogenic gas processing plant. On the Effective
Date, as required by the Note Purchase Agreement, CREH transferred its ownership
of two low temperature separation plants located at the Elk Hills field to Elk
Hills Power.

Prior to our Effective Date, we held 50% of the Class A common interest and
95.25% of the Class C common interest in the Ares JV. ECR held 50% of the Class
A common interest, 100% of the Class B preferred interest and 4.75% of the Class
C common interest. The Ares JV was required to distribute each month its excess
cash flow over its working capital requirements first to the Class B holders and
then to the Class C common interests, on a pro-rata basis. As contemplated by
the terms of the JV, CREH purchased electricity and gas processing services from
the Ares JV (subject to certain limitations, including certain geographical
limitations) in exchange for monthly capacity payments pursuant to the terms of
a Commercial Agreement, the proceeds of which were used by the Ares JV to make
distributions as contemplated by the Second Amended and Restated Limited
Liability Company Agreement of Elk Hills Power, LLC. CREH also served as the
operator of the Ares JV and provided operational and support services in
exchange for a monthly fee pursuant to a Master Services Agreement. These
agreements became intercompany agreements on the Effective Date and were
cancelled as described below.

As described above in Business Environment and Outlook and Part I, Item 1 -
Financial Statements, Note 1 Chapter 11 Proceedings, we entered into the
Settlement Agreement with ECR and Ares which, among other things, changed the
liquidation preference for the Class B member interest to $835 million,
decreased the preferred return from 13.5% per annum to 9.5% per annum payable at
the end of each month, removed the liquidation premium for the Class A common
interest and removed the payment of any previously accrued but unpaid preferred
distributions plus a make-whole payment that ECR, as the holder of the Class B
preferred interests, would otherwise have been entitled to in the event of a
redemption transaction. The Settlement Agreement granted us the right
(Conversion Right) to acquire all (but not less than all) of the equity
interests of Elk Hills Power owned by ECR in exchange for the EHP Notes, Ares
Settlement Stock and $2.5 million in cash. The Conversion right was deemed to
have been exercised on the Effective Date.

Although certain provisions in the Settlement Agreement were not effective until
certain conditions were met, such as the Bankruptcy Court entering a final
order, we determined that the amended terms were substantively different such
that the existing Class A common, Class B preferred and Class C common member
interests held by ECR were treated as redeemed in exchange for new member
interests issued at fair value. The estimated fair value of the new member
interests was lower than the carrying value of the existing member interests by
$138 million. In accordance with GAAP, the return from noncontrolling interest
holders was recorded to additional paid-in capital on our condensed consolidated
balance sheet as of September 30, 2020. However as required by GAAP, the return
is included in our earnings per share calculations. See Part I, Item 1 -
Financial Statements, Note 10 Earnings per Share for adjustments to net income
(loss) attributable to common stock which include a return from noncontrolling
interests.

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We were deemed to have exercised the Conversion Right on the Effective Date and
we issued the EHP Notes in the aggregate principal amount of $300 million, Ares
Settlement Stock comprising approximately 20.8% (subject to dilution) of the new
common stock (Conversion) and $2.5 million in cash. Upon the Conversion, Elk
Hills Power became an indirect wholly-owned subsidiary, and Ares and its
affiliates ceased to have any direct or indirect interest in Elk Hills Power,
other than any interest Ares may have indirectly through its interests in the
EHP Notes and Ares Settlement Stock. In connection with the Conversion, Elk
Hills Power's limited liability company agreement was amended and restated.

In connection with the Conversion, on the Effective Date, we entered into a
Sponsor Support Agreement dated the Effective Date (Support Agreement) pursuant
to which, among other things, the parties agreed that Elk Hills Power will be
our primary provider of electricity to, and will be the primary processor of our
natural gas produced from, the Elk Hills field, which is already consistent with
our current practice.

On the Effective Date, in connection with the Conversion, we terminated: (a) the
Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills
Power and CREH and (b) the Master Services Agreement, dated as of February 7,
2018, by and between Elk Hills Power and CREH.

For more information on the Ares JV, see Part I, Item 1 - Financial Statements,
Note 7 Joint Ventures. For more information on the Settlement Agreement, see
Part I, Item 1 - Financial Statements, Note 1 Chapter 11 Proceedings.

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 have demonstrated that we can
significantly reduce our operating costs in response to prevailing market
conditions. As a result, we continue to believe that a significant portion of
our operating costs are variable over the lifecycle of our fields. 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 and nine months ended September 30, 2020
and 2019:
                                     Three months ended            Nine months ended
                                       September 30,                 September 30,
                                   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 Net Production (MBoe/d)     106               128         113               130


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 September 30, 2020 compared to the same period in
2019, total daily production decreased by approximately 22 MBoe/d or 17%. The
decrease in production related to higher downtime caused by significantly
reduced well repair work, as well as the temporary shut-in of certain wells
beginning in March 2020, which negatively impacted our net production for the
three months ended September 30, 2020 by 3 MBoe/d compared to the same
prior-year period. Due to the lower price environment, our PSC-type contracts
positively impacted our oil production in the third quarter of 2020 by
approximately 1 MBoe/d compared to the same period in 2019. Excluding the
effects of shut-in production and PSC-type contracts, our base decline was still
in line with our previously disclosed rate of low to mid-teens, which largely
resulted from low internal capital investment and well repair work.

For the nine months ended September 30, 2020 compared to the same period in
2019, total daily production decreased by approximately 17 MBoe/d or 13%. The
decrease in production related to higher downtime caused by significantly
reduced well repair work, as well as the temporary shut-in of certain wells
beginning in March 2020, and the effect of the May 2019 partial divestiture of
the Lost Hills field, which negatively impacted our net production for the nine
months ended September 30, 2020 by 3 MBoe/d compared to the same prior-year
period. Due to the lower price environment, our PSC-type contracts positively
impacted our oil production in the nine months of 2020 by 3 MBoe/d compared to
the same period in 2019. Excluding the effects of the Lost Hills transaction,
shut-in production and PSC-type contracts, our base decline was still in line
with our previously disclosed rate of low to mid-teens, which largely resulted
from low internal capital investment and well repair work.

With an ongoing gradual increase of well repair work, we believe our base decline rate going forward will gradually return to the low to mid-teens.


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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 and nine months ended September 30, 2020 and 2019:


                                                                 Three months ended September 30,
                                                       2020                                               2019
                                         Price                   Realization                Price                Realization
Oil ($ per Bbl)
Brent                             $           43.37                                     $     62.00

Realized price without hedge      $           41.83                  96%                $     62.85                  101%
Settled hedges                                 0.32                                            5.56
Realized price with hedge         $           42.15                  97%                $     68.41                  110%

WTI                               $           40.93                                     $     56.45
Realized price without hedge      $           41.83                  102%               $     62.85                  111%
Realized price with hedge         $           42.15                  103%               $     68.41                  121%

NGLs ($ per Bbl)
Realized price (% of Brent)       $           25.16                  58%                $     23.55                  38%
Realized price (% of WTI)         $           25.16                  61%                $     23.55                  42%

Natural gas
NYMEX ($/MMBtu)                   $            1.93                                     $      2.27

Realized price without hedge
($/Mcf)                           $            2.22                  115%               $      2.73                  120%
Settled hedges                                 0.02                                           (0.01)
Realized price with hedge ($/Mcf) $            2.24                  116%               $      2.72                  120%



                                                                  Nine months ended September 30,
                                                       2020                                               2019
                                         Price                   Realization                Price                Realization
Oil ($ per Bbl)
Brent                             $           42.53                                     $     64.74

Realized price without hedge      $           41.27                  97%                $     65.03                  100%
Settled hedges                                 2.00                                            3.13
Realized price with hedge         $           43.27                  102%               $     68.16                  105%

WTI                               $           38.32                                     $     57.06
Realized price without hedge      $           41.27                  108%               $     65.03                  114%
Realized price with hedge         $           43.27                  113%               $     68.16                  119%

NGLs ($ per Bbl)
Realized price (% of Brent)       $           25.17                  59%                $     31.04                  48%
Realized price (% of WTI)         $           25.17                  66%                $     31.04                  54%

Natural gas
NYMEX ($/MMBtu)                   $            1.92                                     $      2.72

Realized price without hedge
($/Mcf)                           $            2.05                  107%               $      2.82                  104%
Settled hedges                                 0.06                                           (0.01)
Realized price with hedge ($/Mcf) $            2.11                  110%               $      2.81                  103%




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Oil - Brent index and realized prices were lower in both the three and nine
months ended September 30, 2020 compared to the same prior-year periods due to
the combination of the supply increase caused by the Saudi-Russia price war and
the severe demand decline caused by COVID-19. Prices collapsed in March 2020 and
gradually improved to around the current levels in June 2020 as a result of the
significant production curtailments OPEC and other nations implemented in
response to COVID-19.

NGLs - Prices for NGLs increased slightly for the three months ended September
30, 2020 compared to the same period in 2019 due to improvements in negotiated
sales differentials along with stronger NGL values relative to crude. NGL prices
declined for the nine months ended September 30, 2020 compared to the same
prior-year period as steady U.S. production exceeded the COVID-19 related
decline in demand, causing lower domestic NGL prices. We continued to receive
premium prices for NGLs relative to national hub prices.

Natural Gas - Our natural gas realized prices were lower in both the three and
nine months ended September 30, 2020 than the comparable periods of 2019. The
decrease was due to increased nationwide natural gas production and higher
inventories across the U.S. primarily due to lower demand resulting from the
shelter-in-place orders related to COVID-19 that began in March 2020. Prices
were also negatively impacted by lower supply constraints on the SoCalGas system
in 2020 compared to the same period in the prior year. Prices began to increase
in September 2020 anticipating lower future production as a result of reduced
capital investment by producers.

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