What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-05-13 compared with 2020-11-05 · 285 added, 672 removed, 188 unchanged (84% of the section changed)

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

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.

We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate.

We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments.

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.

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.

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).

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;

• All existing equity interests were cancelled and their holders received no distributions.

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).

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.

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases).

On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new equity owners and a significantly improved financial position.

Fresh Start Accounting

We qualified for and adopted fresh start accounting upon emergence from bankruptcy at which point we became a new entity for financial reporting purposes.

We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting.

As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date.

Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

Organization Changes

In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions, making progress towards our lower cost operating model.

We changed our 2021 capital guidance to reallocate investments to downhole maintenance activities, which will result in an increase in estimated 2021 operating costs.

As a result, we expect our sustainable cost savings in general and administrative expense and operating costs to be $80 million in 2021 as compared to 2020 levels.

We believe the steps taken to date have improved our financial condition and streamlined our business.

In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020.

On December 31, 2020, our former President, Chief Executive Officer and director Todd A.

Stevens departed and Mark A.

(Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors.

On March 22, 2021, the Board of Directors appointed Mr.

McFarland as President and Chief Executive Officer on a permanent basis.

On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr.

McFarland as the Chair of our Board of Directors.

McFarland will continue to serve as a director.

Recent Debt Transactions

In January 2021, we completed a private offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes).

The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and our EHP Notes, with the remaining proceeds used to pay down a portion of the outstanding borrowings under our Revolving Credit Facility.

For more information on the terms of Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 5 Debt.

In May 2021, we amended the Revolving Credit Facility to:

• increase our borrowing base from $1.167 billion to $1.2 billion;

• evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million;

• increase our capacity to make certain restricted payments;

• reduce the minimum amount of hedges that we are required to maintain for a rolling 24 month period on reasonably anticipated forecasted crude oil production from 50% to 33% so long as our total net leverage ratio is less than 2.00:1.00;

• increase our maximum hedging limitation to 85% (and permit purchased puts and floors up to 100%) of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids for a 48-month period.

Share Repurchase Program

In May 2021, our Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of our common stock through March 31, 2022.

The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions.

The SRP does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time.

Business Environment and Industry Outlook

Commodity Prices

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.

Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables.

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:

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 natural gas reserves we can economically produce over the longer term.

Global oil prices gradually increased beginning in October 2020 through the first quarter of 2021.

Benchmark prices for Brent crude oil in the first quarter of 2021 increased approximately 35% from the fourth quarter of 2020 demonstrating a strong recovery from the prior year when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) pandemic.

Current pricing has benefited from the gradual re-opening of the economy and the lifting of restrictions related to the COVID-19 pandemic.

Further, members of Organization of Petroleum Exporting Countries (OPEC) and non-OPEC producers have restrained crude oil production attempting to reduce oil supplies built during the worst period of the pandemic.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2021, December 31, 2020 and March 31, 2020:

Three months ended

September 30, Nine months ended

September 30,

March 31, Three months ended

December 31, Three months ended

2021 2020 2020

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MMBtu refers to one million British Thermal Units.

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 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

See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production and Prices and Part II, Item 1A – Risk Factors in our 2020 Annual Report for further discussion regarding the impact of the pandemic and declines in commodity prices.

Recent Developments

Certain actions of the new U.S.

administration could impact the oil and gas industry.

Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production.

Such outcomes could materially and adversely affect our business, results of operations and financial condition.

On April 23, 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045.

This marks a reversal from the governor’s previous statements that he lacked the executive authority to ban hydraulic fracturing, and any decision to prohibit the extraction of oil would likely be subject to significant opposition and legal challenge.

Regardless of whether or not such a ban is upheld, we expect little to no impact on future development activities because we are not dependent on well stimulation treatments.

Less than 1% of our proved reserves require well stimulation and our current long-term development plans do not include well stimulation.

We have the largest privately held oil and natural gas mineral acreage position in California, consisting of 2.1 million net mineral acres spanning four of California's major oil and natural gas basins.

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.

Approximately 65% of our mineral acreage is held in fee and the remainder is leased.

Of our leased acreage, approximately 50% is held by production and the remainder is subject to lease expiration if initial producing wells are not drilled within a specified period of time.

The primary terms of our leases range from one to ten years.

The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained.

As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells in response to a low commodity price environment while retaining our oil and gas leases which are held by production.

With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities.

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.

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.

Beyond our essential role in supplying Californians with oil, natural gas, NGLs and electricity, our 2030 Sustainability Goal for carbon is to design and permit California’s first carbon capture and sequestration system by mid-decade which is expected to reduce carbon emissions associated with our operations and significantly extend the productive life of our Elk Hills field.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin 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 operating costs.

We record a share of production and reserves to recover a portion of such capital and operating 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.

(i) to recover our partners’ share of capital and operating 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.

Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating 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.

These contracts represented approximately 16% of our net production for the three months ended March 31, 2021.

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.

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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.

This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our oil, natural gas and NGL sales revenue, general and administrative expenses and operating costs but has no effect on our net results.

Marketing Arrangements

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.

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.

Crude Oil — We sell almost all of our crude oil into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S.

Substantially all of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems.

We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong.

California is heavily reliant on imported sources of energy, with approximately 70% of oil and 90% of natural gas consumed in 2019 imported from outside the state.

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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.

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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.

Natural Gas — We sell all of our natural gas not used in our operations into the California markets on a daily basis at average monthly index pricing.

Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity in the market and producing areas.

Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada.

As a result, we typically enjoy higher netback 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 approximately 11% of our revenue from oil, natural gas and NGL sales are from natural gas.

In addition to selling our produced natural gas, we also purchase natural gas for use in steam generation for our steamfloods and power generation.

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 more volumes sold than used.

Conversely, lower natural gas prices lower our operating costs but have a net negative effect on our financial results.

We currently have transportation capacity contracts to transport the majority of our natural gas volumes until September 2023.

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.

In addition, infrastructure constraints and seasonality can magnify price volatility.

Our earnings are also affected by the performance of our complementary natural gas-processing plants.

We process our wet gas to extract NGLs and other natural gas byproducts.

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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 currently have a pipeline delivery contract to transport 6,500 barrels per day of NGLs to market through March 2023.

Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped.

We have thus far met all of our shipping commitments under this contract.

We sell virtually all of our NGLs using index-based pricing.

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Approximately 30% 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.

Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces field operating costs and provides a reliable source of power.

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)

Total Capital Investment $ 583

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

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

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.

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.

The power sold to the utility is subject to an agreement through the end of 2023, which includes 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 wholesale power market.

The prices obtained for excess power impact our earnings but generally by a relatively small amount.

Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows.

Our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred on the Effective Date, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date.

The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.

We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report if our leverage ratio is greater than 2.00:1.00.

If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are required to maintain is reduced from 50% to 33%.

Currently, we may not hedge more than 85% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period.

In the three months ended March 31, 2021, we added hedges on one million barrels of production for the period from April 2021 to March 2022 at a weighted-average Brent price of approximately $61 per barrel.

See Liquidity and Capital Resources below for a current table summarizing our outstanding derivative contracts.

While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a material driver of changes in our quarterly results.

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.

Our operating 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.

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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.

The measures taken to address the industry downturn in the prior year demonstrate that we can significantly reduce our operating costs in response to prevailing market conditions.

We further 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 in a safe and responsible manner throughout their lifecycles.

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:

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, 2021 and 2020:

Successor Predecessor

Three months ended

September 30, Nine months ended

September 30,

2020 2019 2020 2019

March 31, Three months ended

San Joaquin Basin 38 47

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Ventura Basin 2 4

Total 64 79 70 81

NGLs (MBbl/d)

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Ventura Basin — —

Total 14 16 14 16

Natural gas (MMcf/d)

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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.

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,

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%

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,

For the three months ended March 31, 2021 compared to the same period in 2020, total daily production decreased by approximately 22 MBoe/d or 18%.

The decrease in production largely resulted from limited drilling and capital investment during the prior 12 months.

Our average drilling rigs decreased from 7 in the three months ended March 31, 2020 to 1 rig in the three months ended March 31, 2021.

In addition, production was also negatively impacted by 1 MBoe/d in the first quarter of 2021 compared to 2020 due to downtime at one of our gas processing plants.

Our PSC-type contracts negatively impacted our oil production in the first quarter of 2021 by approximately 3 MBoe/d compared to the same period in 2020.

Our total daily production decreased by approximately 15% compared to the same period in 2020 after excluding the impact of PSC-type contracts and unscheduled downtime at one of our natural gas processing plants.

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, 2021 and 2020:

Successor Predecessor

Three months ended March 31, Three months ended March 31,

Price Realization Price Realization

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Realized price with hedge ($/Mcf) $ 3.25 119% $ 2.35 115%

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.

Balance Sheet Analysis

Balance sheet accounts and changes in these accounts, as of September 30, 2020 and December 31, 2019, are discussed below:

September 30, December 31,

(Debtor-in-Possession:

Entity Operating Under Chapter 11) 2020 2019

(in millions)

Trade receivables

Other current assets, net

Property, plant and equipment, net

$ 4,360 $ 6,352

Other assets $ 76 $ 115

Current portion of long-term debt $ — $ 100

Debtor-in-possession financing $ 733 $ —

Accounts payable $ 221 $ 296

Accrued liabilities $ 240 $ 313

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 attributable to common stock $ (2,341) $ (389)

Equity attributable to noncontrolling interests $ 68 $ 93

Cash — Cash at September 30, 2020 and December 31, 2019 included restricted cash of $24 million and $3 million, respectively.

See Liquidity and Capital Resources for our cash flow analysis.

Trade receivables — The decrease in trade receivables was largely driven by lower realized product prices and lower production volumes in September 2020 compared to December 2019.

Other current assets, net — The decrease in other current assets, net was primarily due to collections from our joint interest partners, an impairment in March 2020 of unrecovered capital investments and a decrease in the fair value of the current portion of our derivative contracts.

The decrease in fair value of our derivative contracts primarily related to a lower percentage of our oil production hedged between comparative periods.

Property, plant and equipment, net — The decrease in property, plant and equipment, net primarily resulted from an impairment of certain proved and unproved properties recorded in the first quarter of 2020, depreciation, depletion, and amortization (DD&A) and sales of certain royalty interests and non-core assets in January 2020.

For further detail about our asset impairment, see Part I, Item 1 – Financial Statements, Note 15 Asset Impairments .

Other assets — Other assets decreased primarily due to the utilization of parts for a scheduled turnaround at our Elk Hills power plant as well as a decrease in operating lease assets due to releasing drilling rigs, both of which occurred in the first quarter of 2020.

Current portion of long-term debt — Current maturities of long-term debt decreased by $100 million reflecting

the payoff of our 2020 Senior Notes in January 2020.

Debtor-in-possession financing — As a result of our Chapter 11 Cases, we obtained debtor-in-possession financing to allow us to continue operating our business during the pendency of the bankruptcy proceedings.

Proceeds from the debtor-in-possession financing were used to pay off our 2014 Revolving Credit Facility.

See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession credit agreements.

Accounts payable — The amount due to our vendors decreased as a result of our reduced capital program and lower activity levels in the third quarter of 2020 as compared to the fourth quarter of 2019.

Accrued liabilities — The decrease in accrued liabilities primarily related to bonus payments made to employees in the first quarter of 2020, releasing drilling rigs, and lower drilling and completion activity related to the Alpine JV due to the suspension of further capital funding as a result of low commodity prices.

These decreases were partially offset by accrued legal, professional and other fees related to our Chapter 11 Cases and an increase in our liability for property taxes due to the timing of payments.

As of September 30, 2020, accrued interest on our long-term debt impaired by our Chapter 11 Cases was presented as LSTC on our condensed combined balance sheet.

See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information about liabilities subject to compromise.

Long-term debt — The decrease in long-term debt related to the reclassification of long-term debt to LSTC on our condensed combined balance sheet as of September 30, 2020.

See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information.

Deferred gain and issuance costs, net — The decrease in deferred gain and issuance costs, net resulted from the elimination of unamortized amounts associated with our pre-petition long-term debt as a result of Chapter 11 Cases.

Liabilities subject to compromise — The increase resulted from the reclassification of our long-term debt along with related accrued interest as of the petition date as liabilities subject to compromise on our condensed consolidated balance sheet as of September 30, 2020.

Mezzanine equity — The decrease in mezzanine equity primarily resulted from the deemed redemption of the equity interests in our Ares JV held by ECR for less than their carrying amount.

See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures and Development Joint Ventures above for additional information on the Settlement Agreement and the Ares JV.

Equity attributable to common stock — Equity attributable to common stock decreased primarily as a result of the net loss in the nine months ended September 30, 2020.

Equity attributable to noncontrolling interests — Equity attributable to noncontrolling interests includes BSP's preferred interest in the BSP JV.

The decrease primarily related to distributions to our joint venture partner.

Oil — Brent index and realized prices without hedge settlements were higher in the three months ended March 31, 2021 compared to the same prior-year period due to a recovery in oil demand from the severe demand decline caused by COVID-19 in 2020.

Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing restrictions and the significant production curtailments by OPEC members and Russia.

Further, most producers in other nations also curtailed production and significantly reduced their capital investments in response to COVID-19 in 2020, which continued into 2021.

NGLs — Prices for NGLs increased for the three months ended March 31, 2021 compared to the same period in 2020 as supply in 2020 outpaced demand, causing lower NGL prices in the first quarter of 2020.

In the first quarter of 2021, producers continued to curtail production and the tighter supply resulted in higher benchmark prices and price realizations as compared to the same prior year period.

Natural Gas — Our natural gas realized prices were higher in the three months ended March 31, 2021 than the comparable period of 2020 due to increased natural gas demand in the nationwide markets.

This was a significant change from the first quarter of 2020 in which demand decreased as a result of shelter-in-place orders related to COVID-19.

Statements of Operations Analysis

We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting.

As a result of the application of fresh start accounting and the implementation of the Plan, our results of operations for the Successor period may not be comparable with that of the Predecessor period.

Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

Results of Oil and Gas Operations

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three and nine months ended September 30, 2020 and 2019:

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended March 31, 2021 and 2020:

Successor Predecessor

Three months ended

September 30, Nine months ended

September 30,

March 31, Three months ended

Energy operating costs (a)

$ 4.70 $ 3.71

Production costs $ 14.52 $ 18.82 $ 14.85 $ 19.32

Production costs, excluding effects of PSC-type contracts (a)

Gas processing costs 0.53 0.67

Non-energy operating costs (b)

Operating costs $ 18.33 $ 17.38

Operating costs, excluding effects of PSC-type contracts (c)

$ 16.72 $ 16.48

Field general and administrative expenses (b)

Field general and administrative expenses (d)

$ 0.89 $ 1.09

Field depreciation, depletion and amortization (b)

Field depreciation, depletion and amortization (d)(e)

$ 5.14 $ 10.05

Field taxes other than on income (b)

Field taxes other than on income (d)

$ 3.46 $ 3.08

(a) As described in the Operations section, 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.

These amounts represent our production costs after adjusting for this difference.

(b) Excludes corporate expenses.

(a) Energy operating costs include purchases of fuel gas and electricity used in our operations and internal costs to produce electricity used in our fields.

(b) Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

(c) As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.

These amounts represent our operating costs after adjusting for this difference.

(d) Excludes corporate expenses.

(e) Field depreciation, depletion and amortization decreased in the three months ended March 31, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the fresh start valuation of our property, plant and equipment.

Consolidated Results of Operations

The following table presents our consolidated results of operations and key financial measures for the three and nine months ended September 30, 2020 and 2019:

The following table presents our consolidated results of operations and key financial measures for the three months ended March 31, 2021 and 2020:

Successor Predecessor

Three months ended

September 30, Nine months ended

September 30,

2020 2019 2020 2019

March 31, Three months ended

(in millions)

Oil and natural gas sales $ 312 $ 541 $ 987 $ 1,720

Net derivative gain (loss) from commodity contracts — 37 75 (31)

Marketing and trading revenue 50 62 109 230

Oil, natural gas and NGL sales $ 432 $ 430

Net derivative (loss) gain from commodity contracts (213) 79

Trading revenue 98 45

Electricity sales 33 13

Other revenue 13 6

Production costs (141) (221) (460) (684)

Operating costs (164) (192)

General and administrative expenses (48) (60)

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Exploration expense (2) (5)

Marketing and trading costs (35) (45) (67) (170)

Trading costs (61) (24)

Electricity cost of sales (24) (16)

1 unchanged sentence

Other expenses, net (30) (16)

Reorganization items, net 66 — 66 —

Reorganization items (2) —

Interest and debt expense, net (13) (87)

Net gain on early extinguishment of debt (2) 5

Gain on asset divestitures 2 —

Other non-operating expenses (1) (14)

(Loss) income before income taxes (7) 127 (1,999) 124

Loss before income taxes (89) (1,745)

Income tax — —

Net (loss) income (7) 127 (1,999) 124

Net loss (89) (1,745)

Net income attributable to noncontrolling interests (5) (51)

Net (loss) income attributable to common stock $ (29) $ 94 $ (2,096) $ 39

Adjusted net (loss) income (a)

$ (55) $ 17 $ (265) $ 34

Adjusted EBITDAX (a)

$ 103 $ 278 $ 373 $ 834

Effective tax rate — % — % — % — %

(a) Adjusted net (loss) income and adjusted EBITDAX are non-GAAP measures.

See the Non-GAAP Financial Measures section below for reconciliations to their nearest U.S.

GAAP equivalent.

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 pre-emergence equity-settled awards granted to executives included stock options, restricted stock units and performance stock units that either cliff vested at the end of a three-year period or vested ratably over a three-year period, some of which are partially settled in cash.

Our pre-emergence equity-settled awards granted to non-employee directors included stock grants that vested immediately or restricted stock units that cliff vested after one year.

Our cash-settled awards granted to non-executive employees vested ratably over a three-year period.

Unvested awards granted to employees and non-employee directors were cancelled at the Effective Date pursuant to the Plan.

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, accounted for approximately 40% of our total outstanding awards at September 30, 2020.

Our obligations for equity-settled awards are not similarly adjusted for changes in our stock price.

Three months ended September 30, 2020 vs.

Oil and natural gas sales — Oil and natural gas sales decreased 42%, or $229 million, for the three months ended September 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

Net loss attributable to common stock $ (94) $ (1,796)

Three months ended March 31, 2021 vs.

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $432 million for the three months ended March 31, 2021, which is an increase of $2 million compared to $430 million for the same period of 2020.

The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table:

Oil NGLs Natural Gas Total

(in millions)

Three months ended September 30, 2019 $ 457 $ 34 $ 50 $ 541

Three months ended March 31, 2020 $ 356 $ 36 $ 38 $ 430

Changes in realized prices 71 24 18 113

Changes in production (96) (6) (9) (111)

Three months ended September 30, 2020 $ 246 $ 32 $ 34 $ 312

Three months ended March 31, 2021 $ 331 $ 54 $ 47 $ 432

See Production and Prices for index prices, realizations and production volumes for comparative periods.

The effect of settled hedges is not included in the table above.

Net proceeds from settled hedges were $2 million for the three months ended September 30, 2020 compared to net proceeds of $40 million for the same period of 2019.

Including the effect of settled hedges, our oil and natural gas revenue decreased by $424 million or 51% compared to the same prior-year period.

Net derivative gain (loss) from commodity contracts — We did not have a net derivative gain or loss from commodity contracts for the three months ended September 30, 2020 compared to a gain of $37 million in the same period of 2019.

Non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices, volatility, time to expiration and the associated forward curves.

Three months ended

September 30,

(in millions)

Non-cash derivative gain (loss), excluding noncontrolling interest $ 4 $ (6)

Non-cash derivative (loss) gain, noncontrolling interest (6) 3

Total non-cash changes (2) (3)

Net proceeds on settled commodity derivatives 2 40

Net derivative gain from commodity contracts $ — $ 37

Production costs — Production costs for the three months ended September 30, 2020 decreased $80 million to $141 million compared to $221 million for the same period of 2019, resulting in a 36% decrease.

Excluding employee incentive compensation, our production costs decreased $83 million to $134 million for the three months ended September 30, 2020 from $217 million during the same prior-year period.

The decrease was primarily attributable to efficiencies and streamlining of our operations along with workforce reductions.

Also contributing to the decrease were lower operating costs due to shut-in wells, as well as reduced activity levels, such as downhole maintenance, in response to the current economic environment.

Three months ended

September 30,

(in millions)

Production costs $ 141 $ 221

Stock-based compensation — 1

Other employee incentive awards (7) (5)

Production costs, excluding employee incentive compensation $ 134 $ 217

General and administrative expenses — Our general and administrative (G&A) expenses were $64 million for the three months ended September 30, 2020 compared to $66 million for the three months ended September 30, 2019.

Excluding employee incentive compensation and severance, our G&A expenses decreased $11 million to $44 million for the three months ended September 30, 2020 from $55 million for the same prior-year period.

The decrease in G&A expenses, excluding employee incentive compensation and severance, resulted from our ongoing cost saving efforts, our August 2020 workforce reduction and a decline in spending across a number of cost categories.

These savings were partially offset by obtaining additional insurance as a result of our Chapter 11 Cases.

The $10 million increase in other employee incentive awards for the three months ended September 30, 2020 from the same period in 2019 was primarily the result of changes to the variable portion of our incentive compensation program in May 2020, which was approved by the Bankruptcy Court, and a higher payout approved on pre-established performance metrics.

For additional information on the variable compensation program, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings and General above.

Payments for settled hedges were $39 million for the three months ended March 31, 2021 compared to proceeds of $98 million, including $63 million of proceeds from derivative contracts sold prior to maturity, for the same period of 2020.

Including the effect of settled hedges, our oil, natural gas and NGL revenue decreased by $135 million or 26% compared to the same prior-year period.

Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $213 million for the three months ended March 31, 2021 compared to a net gain of $79 million in the same period of 2020.

The non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices and the associated forward curves.

Three months ended

September 30,

(in millions)

G&A expenses $ 64 $ 66

Stock-based compensation (1) (1)

Other employee incentive awards (19) (9)

Severance — (1)

G&A expenses, excluding employee incentive compensation and severance $ 44 $ 55

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $29 million to $89 million in the third quarter of 2020 compared to $118 million in 2019 was predominately due to a decrease in our depletable basis as a result of our asset impairment recorded in March 2020.

For further detail about our asset impairment, see Part I, Item 1 – Financial Statements, Note 15 Asset Impairments .

Reorganization items, net — We recognized a $66 million net gain in the third quarter of 2020 primarily due to the write-off of the unamortized balance of our deferred gain, original issue discounts and deferred issuance costs on our long-term debt partially offset by increased legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings.

See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information about reorganization items, net.

Interest and debt expense, net — Interest and debt expense, net decreased $67 million to $28 million in the third quarter of 2020 compared to $95 million in the same period of 2019 primarily due to suspending the accrual of interest on our pre-petition long-term debt obligations as of the petition date, a lower overall debt balance primarily resulting from repayment of our 2020 Senior Notes in January 2020 and repurchases of our Second Lien Notes in 2019, and lower variable interest rates on borrowings under our 2016 Credit Agreement and 2017 Credit Agreement.

The decrease was partially offset by interest on our debtor-in-possession financing.

See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession financing.

Net gain on early extinguishment of debt — We did not repurchase any debt during the three months ended September 30, 2020, compared to recognizing a debt extinguishment gain of $82 million in the same period of 2019 related to repurchases of our Second Lien Notes.

Other non-operating expense — Other non-operating expense increased $24 million to $32 million for the three months ended September 30, 2020 compared to $8 million in the same period for 2019.

The increase was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, incurred prior to our petition date, as well as a one-time severance charge related to our August 2020 workforce reduction.

Net income attributable to noncontrolling interests — The decrease of $11 million in net income attributable to noncontrolling interests to $22 million for the quarter ended September 30, 2020 from $33 million for the same period in 2019 was primarily related to lower revenue from the net profits interest held by the BSP JV and changes in derivative gain (loss) due to a decline in commodity prices between periods.

See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information.

Nine months ended September 30, 2020 vs 2019

Oil and natural gas sales — Oil and natural gas sales decreased 43%, or $733 million, for the nine months ended September 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

Oil NGLs Natural Gas Total

(in millions)

Nine months ended September 30, 2019 $ 1,433 $ 132 $ 155 $ 1,720

Changes in realized prices (525) (24) (43) (592)

Changes in production (113) (14) (14) (141)

Nine months ended September 30, 2020 $ 795 $ 94 $ 98 $ 987

See Production and Prices for index prices, realizations and production volumes for comparative periods.

The effect of settled hedges is not included in the table above.

Net proceeds from settled hedges were $42 million for the nine months ended September 30, 2020, excluding the effect of our derivative contracts sold prior to maturity in the first quarter of 2020, compared to net proceeds of $68 million for the same period of 2019, which had a negative impact of $26 million on our total revenue between periods.

Including the effect of settled hedges and proceeds from derivative contracts sold in the first quarter of 2020, our oil and natural gas revenue decreased by $696 million or 39% compared to the same prior-year period.

Net derivative gain (loss) from commodity contracts — Net derivative gain from commodity contracts was $75 million for the nine months ended September 30, 2020 compared to a loss of $31 million in the same period of 2019, representing an overall change of $106 million as reflected in the following table.

Nine months ended

September 30,

March 31, Three months ended

(in millions)

2 unchanged sentences

Total non-cash changes (174) (19)

Net proceeds on settled commodity derivatives 42 68

Net proceeds on derivative sales prior to maturity 63 —

Net derivative gain (loss) $ 75 $ (31)

Marketing and trading revenue — The decrease in marketing and trading revenue of $121 million to $109 million for the nine months ended September 30, 2020 compared to $230 million in the same period of 2019 was due to lower volumes related to our natural gas trading activities.

Production costs — Production costs for the nine months ended September 30, 2020 decreased $224 million to $460 million compared to $684 million for the same period of 2019, resulting in a 33% decrease.

Excluding employee incentive compensation, our production costs decreased $216 million to $443 million for the nine months ended September 30, 2020 from $659 million during the same prior-year period.

The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our workforce reductions and reduced work schedules during the months of April and May 2020.

The operating costs of shut-in wells, as well as lower activity levels in response to the current environment, such as downhole maintenance, also contributed to the decrease.

Nine months ended

September 30,

(in millions)

Production costs $ 460 $ 684

Stock-based compensation — (7)

Other employee incentive awards (17) (18)

Production costs, excluding employee incentive compensation $ 443 $ 659

General and administrative expenses — Our G&A expenses were $193 million for the nine months ended September 30, 2020 and decreased $35 million from $228 million for the nine months ended September 30, 2019.

Excluding employee incentive compensation and severance, our G&A expenses decreased $27 million to $148 million for the nine months ended September 30, 2020 from $175 million for the same prior-year period.

The decrease in G&A expenses, excluding employee incentive compensation, resulted from cost saving efforts, workforce reductions, reduced work hours in April and May 2020 and a decline in spending across a number of cost categories.

These savings were partially offset by the cost of obtaining additional insurance due to our Chapter 11 Cases and lower cost capitalization as a result of temporarily suspending our capital program.

The $12 million increase in other employee incentive awards for the nine months ended September 30, 2020 from the same period in 2019 was primarily the result of changes to the variable portion of our incentive compensation program in May 2020, which was approved by the Bankruptcy Court, and a higher payout approved on pre-established performance metrics.

For additional information on the variable compensation program, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings and General above.

Nine months ended

September 30,

(in millions)

G&A expenses $ 193 $ 228

Stock-based compensation (3) (21)

Other employee incentive awards (42) (30)

Severance — (2)

G&A expenses, excluding employee incentive compensation and severance $ 148 $ 175

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $61 million to $296 million for the nine months ended September 30, 2020 from to $357 million for the same period in 2019 was predominately due to a decrease in our depletable basis as a result of our asset impairment recorded in the first quarter of 2020.

Asset impairments — In the first quarter of 2020, we recorded an impairment charge of $1.7 billion, of which $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that we no longer intend to pursue.

No asset impairments were recorded in the second or third quarters of 2020.

For further detail about our first quarter 2020 asset impairment, see Part I, Item 1 – Financial Statements, Note 15 Asset Impairments .

Marketing and trading costs — Marketing and trading costs decreased $103 million to $67 million for the nine months ended September 30, 2020 compared to $170 million in the same prior-year period.

The decrease was predominantly the result of lower volume related to our natural gas trading activities.

Other expenses, net — The increase in other expenses of $42 million to $75 million for the nine months ended September 30, 2020 compared to $33 million for the same period of 2019 was largely the result of a one-time deficiency payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract and a scheduled plant turnaround at the Elk Hills power plant in the first quarter of 2020.

Reorganization items, net — We recognized a $66 million net gain in the third quarter of 2020 primarily due to the write-off of the unamortized balance of deferred gain, original issue discounts and deferred issuance costs on our long-term debt partially offset by increased legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings.

See Part I, Item 1 – Financial Statements, Note 2 Basis of Presentation for additional information about reorganization items, net.

Interest and debt expense, net — Interest and debt expense, net decreased $93 million to $200 million in the nine months ended September 30, 2020 compared to $293 million in the same period of 2019 primarily due to suspending the accrual of interest on our pre-petition long-term debt obligations as of July 15, 2020, a lower overall debt balance primarily resulting from repayment of our 2020 Senior Notes in January 2020 and repurchases of our Second Lien Notes in 2019, and lower variable interest rates on borrowings under our 2016 Credit Agreement and 2017 Credit Agreement.

This decrease was partially offset by interest on our debtor-in-possession financing.

See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on our debtor-in-possession financing.

Net gain on early extinguishment of debt — The net gain on early extinguishment of debt for the nine months ended September 30, 2020 was $5 million, which is a decrease of $103 million from $108 million during the same period in 2019.

The decrease was due to lower debt repurchase activity in 2020.

Other non-operating expense — Other non-operating expense increased $75 million to $93 million for the nine months ended September 30, 2020 compared to $18 million in the same period of 2019.

Net income attributable to noncontrolling interests — The increase of $12 million in net income attributable to noncontrolling interests to $97 million for the nine months ended September 30, 2020 from $85 million for the same period in 2019 was primarily a result of limitations on the amount of losses allocable to ECR's Class C member interest in 2020.

See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information on the Ares JV.

Non-GAAP Financial Measures

Adjusted net (loss) income — Our results of operations, which are presented in accordance with U.S.

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 a measure called adjusted net income (loss) that excludes those items.

This measure is not meant to disassociate these items from management's performance but rather is meant to provide useful information to investors interested in comparing our performance between periods.

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 (loss) income to the non-GAAP financial measure of adjusted net (loss) income and presents the GAAP financial measure of net (loss) income attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net (loss) income per diluted share:

Three months ended

September 30, Nine months ended

September 30,

2020 2019 2020 2019

(in millions, except share data)

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:

Asset impairment — — 1,736 —

Non-cash derivative (loss) gain from commodities, excluding noncontrolling interest (4) 6 31 99

Reorganization items, net:

(66) — (66) —

Unamortized deferred gain (171) — (171) —

Unamortized deferred issuance costs and original issue discounts 46 — 46 —

Legal, professional and other items during bankruptcy, net 34 — 34 —

Debtor-in-possession financing costs 25 — 25 —

Severance and termination benefits 10 — 10 2

Incentive and retention award modification — — 4 —

Net gain on early extinguishment of debt — (82) (5) (108)

Legal, professional and other fees pre-bankruptcy 15 — 64 —

Deficiency payment on a pipeline delivery contract — — 20 —

Planned 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 diluted share (a)

2.20 1.89 (39.64) 0.77

Adjusted net income (loss) per diluted share (a)

1.68 0.35 (2.57) 0.69

(a) Net income (loss) and adjusted net income (loss) per diluted share for the three and nine months ended September 30, 2020 include a $138 million gain related to the deemed redemption of the noncontrolling interest in the Ares JV.

See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information about our Settlement Agreement and the Ares JV.

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.

We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders.

Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP.

Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets.

This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted EBITDAX:

Three months ended

September 30, Nine months ended

September 30,

2020 2019 2020 2019

(in millions)

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 (26) (77) 1,831 (5)

Other non-cash items 17 10 36 40

Adjusted EBITDAX $ 103 $ 278 $ 373 $ 834

The following table sets forth a reconciliation of the GAAP measure of net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX:

Nine months ended

September 30,

(in millions)

Net cash provided by operating activities $ 141 $ 540

Cash interest 80 300

Exploration expenditures 9 15

Working capital changes, excluding accrued interest 143 (21)

Adjusted EBITDAX $ 373 $ 834

Adjusted G&A — Management uses a measure called adjusted general and administrative (adjusted G&A) expense to provide useful information to investors interested in comparing our costs between periods and performance to our peers.

We define adjusted G&A expenses as general and administrative expenses excluding severance and other non-recurring costs.

The following table presents the reconciliation of our general and administrative expenses to the non-GAAP measure of adjusted G&A:

Three months ended September 30, Nine months ended

September 30,

2020 2019 2020 2019

(in millions) (in millions)

General and administrative expenses $ 64 $ 66 $ 193 $ 228

Incentive and retention award modification — — (4) —

Severance costs — (1) — (2)

Adjusted G&A $ 64 $ 65 $ 189 $ 226

Net (payments) proceeds on settled commodity derivatives (39) 35

Net proceeds on derivative contracts sold prior to maturity — 63

Net derivative (loss) gain from commodity contracts $ (213) $ 79

Trading revenue – Trading revenue was $98 million for the three months ended March 31, 2021, an increase of $53 million, or 118% from $45 million during the same period of 2020.

The increase was predominantly the result of higher volume and prices related to our natural gas trading activities.

Our net profit from natural gas trading activities, after consideration of trading costs described below, was $37 million for the three months ended March 31, 2021 compared to $21 million for the same period of 2020.

Electricity sales – Electricity sales increased $20 million to $33 million in the first quarter of 2021 compared to $13 million in the same period of 2020.

There were lower electricity sales in the first quarter of 2020 as a result of planned major maintenance at the Elk Hills power plant.

Operating costs — Operating costs for the three months ended March 31, 2021 were $164 million, which was a decrease of $28 million or 15% from $192 million for the same period of 2020.

The decrease was primarily attributable to efficiencies and streamlining of our operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021.

General and administrative expenses — Our general and administrative (G&A) expenses were $48 million for the three months ended March 31, 2021, which was a decrease of $12 million from $60 million for the three months ended March 31, 2020.

The decrease in G&A expenses were attributable to efficiencies and streamlining of our operations, including a decrease of $7 million in employee related expenses as a result of workforce reductions.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $67 million to $52 million in the first quarter of 2021 compared to $119 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment.

Asset impairments – Asset impairment charges for the three months ended March 31, 2021 were $3 million for the impairment of capitalized costs related to projects which were abandoned.

For the same period in 2020, we recorded an impairment charge of $1.7 billion due to the sharp drop in commodity prices in March 2020, which included $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that was no longer included in our development plans at that time.

See Part I, Item 1 – Financial Statements, Note 14 Asset Impairments for additional information.

Trading costs – Natural gas purchases related to trading activities were $61 million for the three months ended March 31, 2021, which was an increase of $37 million or 154% from $24 million for the same period in 2020.

The change was predominantly the result of higher activity levels and prices related to natural gas trading activities.

Other expenses, net – Other expenses, net was $30 million for the three months ended March 31, 2021, which was an increase of $14 million from $16 million during the same period of 2020.

The increase was largely the result of a restructuring charge related to workforce reductions in the three months ended March 31, 2021.

Interest and debt expense, net — Interest and debt expense, net decreased $74 million to $13 million in the first quarter of 2021 compared to $87 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from bankruptcy.

Additionally, in the first quarter of 2021, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn for two months in the period.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions.

Other non-operating expense — Other non-operating expense decreased $13 million to $1 million for the three months ended March 31, 2021 compared to $14 million in the same period for 2020.

The expense in the first quarter of 2020 was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, which were incurred prior to our petition date, and abandoned transactions.

Net income attributable to noncontrolling interests — Upon emergence from bankruptcy, we acquired all of

ECR's member interests in the Ares JV;

therefore, the allocation of net income to noncontrolling interest

holders in the Successor period for the three months ended March 31, 2021 is lower than the Predecessor period for the three months ended March 31, 2020.

See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information on the settlement terms of the Ares JV.

Liquidity and Capital Resources

Cash Flow Analysis – Pre-Emergence

Nine months ended

September 30,

(in millions)

Cash flow from operating activities

Cash flow from investing activities:

Capital investments $ (37) $ (393)

Decreases in accrued capital investments $ (25) $ (49)

Acquisitions, divestitures and other $ 34 $ 151

Cash flow from financing activities:

Net debt transactions $ 87 $ (178)

Net distributions to noncontrolling interest holders $ (94) $ (66)

Issuance of common stock and other $ (1) $ —

Cash Flow Analysis

Cash flows from operating activities — Our net cash provided by operating activities is sensitive to many variables, including changes in commodity prices.

Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program.

Our operating cash flow decreased 74%, or $399 million, to $141 million for the nine months ended September 30, 2020 from $540 million in the same period of 2019.

The decrease in operating cash flow primarily reflected the significant drop in oil prices between periods.

The decrease was partially offset by a positive $153 million change in operating assets and liabilities, net in the nine months ended September 30, 2020 compared to an increase of $55 million in the comparable nine months of 2019.

The changes in operating assets and liabilities resulted from a decrease in accounts receivable due to lower commodity prices between periods and an increase in accrued liabilities related to our legal and professional fees, partially offset by a decrease related to suspending the accrual of interest on our long-term debt.

Cash flows from investing activities — Our net cash used in investing activities of $28 million for the nine months ended September 30, 2020 primarily reflected $37 million of capital investments (excluding a $25 million decrease in capital-related accrual changes).

Investing activities also included proceeds of $41 million related to a sale of royalty interests and a non-core asset in the nine months ended September 30, 2020.

For the nine months ended September 30, 2019, our net cash used in investing activities of $291 million primarily included approximately $393 million of capital investments (excluding a $49 million decrease in capital-related accrual changes), of which $48 million was funded by BSP, partially offset by $164 million of proceeds related to our Lost Hills sale.

Cash flows from financing activities — Our net cash used in financing activities of $8 million for the nine months ended September 30, 2020 primarily included $518 million in net repayments on our 2014 Revolving Credit Facility and net $733 million of proceeds from our debtor-in-possession financing.

Financing activities also included $100 million for the repayment of the 2020 Senior Notes at maturity, $94 million of distributions to our noncontrolling interest holders, $25 million for our debtor-in-possession financing costs and $3 million for repurchases of our Second Lien Notes.

For the nine months ended September 30, 2019, our net cash used in financing activities of $244 million was primarily comprised of $149 million used for repurchases of our Senior Notes, $115 million of distributions paid to our noncontrolling interest holders, and $27 million of net repayments on our 2014 Revolving Credit Facility partially offset by $49 million in a net contribution from a noncontrolling interest holder.

During the pendency of the Chapter 11 Cases, our primary sources of liquidity were limited to cash flow from operations, cash on hand and available borrowing capacity under our Senior DIP Facility.

After our emergence from Chapter 11, and repayment of the balances outstanding under our debtor-in-possession credit agreements, our primary sources of liquidity are comprised of cash flow from operations and availability under our new Revolving Credit Facility.

We also may rely on other sources, such as non-core asset sales, to supplement our cash flow and fund other corporate purposes.

Our operating cash flow decreased 36%, or $81 million, to $147 million for the three months ended March 31, 2021 from $228 million in the same period of 2020.

The net change in operating cash flow includes decreases primarily from:

(i) settlement payments on our derivative contracts in the first quarter of 2021 compared to proceeds received during the first quarter of 2020 and (ii) a large increase in trade accounts receivable resulting from changes in entry and exit prices between the comparative quarters.

These decreases were partially offset by lower (i) operating costs primarily related to workforce reductions, (ii) interest payments on our long-term debt and (iii) payments of variable compensation as a result of changing from an annual payment in the first quarter of 2020 compared to quarterly payments in the first quarter of 2021.

Cash flows from investing activities — Our net cash used in investing activities increased $8 million, or 67% from $12 million for the three months ended March 31, 2020 to $20 million for the same period in 2021.

Cash used in investing activities included $49 million for capital investment in the three months ended March 31, 2020 compared to $22 million in the three months ended March 31, 2021 due to lower activity levels in 2021.

Capital investments were partially offset by $41 million related to royalty interest and non-core asset sales in the first quarter of 2020 as compared to proceeds of $2 million in the first quarter of 2021 for non-core asset sales.

The table below summarizes net cash used in investing activities for the three months ended March 31, 2021 and 2020 (in millions):

Successor Predecessor

Three months ended March 31, 2021 Three months ended March 31, 2020

(in millions)

Capital investments $ (27) $ (30)

Changes in capital investment accruals 5 (19)

Proceeds from divestitures 2 41

Net cash used in investing activities $ (20) $ (12)

Cash flows from financing activities — Our net cash used in financing activities of $25 million for the three months ended March 31, 2021 included $14 million of distributions to noncontrolling interest holders and a net $11 million of cash used to repay long-term debt.

See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our debt.

Our net cash used in financing activities for the three months ended March 31, 2020 was $156 million and primarily included net repayments of $110 million on our debt obligations and $42 million in net distributions to noncontrolling interest holders.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Notes.

The table below summarizes net cash used by financing activities for the three months ended March 31, 2021 and 2020 (in millions):

Successor Predecessor

Three months ended March 31, 2021 Three months ended March 31, 2020

(in millions)

Debt transactions, net $ (11) $ (110)

Debt repurchases — (3)

Distributions to noncontrolling interest holders, net (14) (42)

Net cash used by financing activities $ (25) $ (156)

Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand and available borrowing capacity under our Revolving Credit Facility.

We emerged from bankruptcy with a strong balance sheet and low leverage.

We have substantially revamped our cost structure while maintaining sustainable operations.

We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining.

At current commodity prices and our planned 2021 capital program described below, we expect to generate positive free cash flow, which may be used to (i) increase investments in our drilling program to accelerate value, (ii) pay dividends or buy back stock to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, or (iii) maintain cash on our balance sheet.

We may be required to begin paying income taxes if Brent prices remain above $60 per barrel for a sustained period.

Our tax paying status depends on a number of factors, including but not limited to, potential legislation which could limit tax incentives for fossil fuels, the amount and type of our capital spend, cost structure and activity levels.

We believe we have sufficient sources of cash to meet our obligations for the next twelve months.

Under our Revolving Credit Facility and Second Lien Term Loan, we will be subject to liquidity requirements under certain conditions.

See Part I, Item 1 – Financial Statements, Note 6 Debt for additional information on the liquidity requirements under our credit agreements.

As of the Effective Date (October 27, 2020), our liquidity was $350 million, which includes $72 million of unrestricted cash and approximately $278 million of availability on our Revolving Credit Facility.

Working Capital

Our working capital requirements are primarily driven by the level of activity in our business, commodity prices and debt service requirements.

Debt and Post-Emergence Capitalization

The commencement of our Chapter 11 Cases constituted an immediate event of default that automatically accelerated our long-term obligations.

Any efforts to enforce payment obligations related to the acceleration of our obligations under our debt agreements were automatically stayed immediately upon filing the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

As of September 30, 2020, the outstanding principal of our long-term debt was $5.1 billion, of which $4.4 billion related to obligations that existed prior to our bankruptcy filing and approximately $700 million related to debtor-in-possession financing.

Our outstanding pre-petition debt was presented as liabilities subject to compromise and our debtor-in-possession financing was presented in total current liabilities on our condensed consolidated balance sheet as of September 30, 2020.

In accordance with the Plan, confirmed by the Bankruptcy Court, significant transactions affecting our liquidity upon emergence from Chapter 11 included the following:

• Approximately $4.4 billion of pre-petition debt was exchanged for new common stock and Warrants;

• We borrowed $225 million on our Revolving Credit Facility, a portion of which was used to repay our Senior DIP Facility;

• Repaid our Junior DIP Facility with $450 million of proceeds from new equity issued under our Subscription Rights offering and $200 million of proceeds from our Second Lien Term Loan;

• Acquired all of the member interest in the Ares JV held by ECR in exchange for the EHP Notes, Ares Settlement Stock and $2.5 million in cash;

• Cash collateralized, on an interim basis, certain letters of credit for $118 million;

• Funded $18 million into a restricted account for payment of certain legal, professional and other fees associated with our restructuring.

Following the Effective Date, cash interest will approximate $50 million per year.

Distributions to noncontrolling interest holders will approximate $18 million per year, which is our required minimum distribution to BSP.

The following table presents our pro forma capitalization after giving effect to certain transactions in the Plan, assuming our Effective Date was on September 30, 2020 (a) :

September 30, 2020

Reorganization Adjustments Pro Forma

Based on the timing of our anticipated cash distributions to Benefit Street Partners (BSP) at current commodity prices, we believe the preferred interest held by BSP in our development joint venture could be automatically redeemed early in the fourth quarter of 2021.

See Part I, Item 1 – Financial Statements, Note 6 Joint Ventures for additional information on our BSP JV.

The following table summarizes our liquidity (in millions):

March 31, April 30,

(in millions)

Senior DIP Facility $ 83 $ (83) $ —

Junior DIP Facility 650 (650) —

Total short-term borrowings 733 (733) —

Unrestricted cash $ 130 $ 123

Revolving Credit Facility:

Second Lien Term Loan — 200 200

EHP Notes — 300 300

2017 Credit Agreement 1,300 (1,300) —

2016 Credit Agreement 1,000 (1,000) —

Second Lien Notes 1,808 (1,808) —

5% Senior Notes due 2020

5.5% Senior Notes due 2021

6% Senior Notes due 2024

Total long-term debt (b)

4,352 (3,627) 725

Mezzanine Equity

Redeemable noncontrolling interests (c)

692 $ (692) —

Equity (2,273) $ 5,052 2,779

Total Capitalization $ 3,504 $ — $ 3,504

(a) The above pro forma adjustments do not reflect all of the adjustments that would be required to present pro forma financial statements in accordance with Article 11 of Regulation S-X.

For example, the effects of fresh start accounting have not been included.

(b) On the Effective Date, we had unrestricted cash of $72 million and an additional $118 million of cash temporarily used to collateralize letters of credit.

(c) See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for more information about our Settlement Agreement and the Ares JV.

For more information on our debt, see Part I, Item 1 – Financial Statements, Note 6 Debt and for more information on our confirmed Plan, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings.

Borrowing capacity (a)

Letters of credit outstanding (125) (125)

Total availability $ 415 $ 367

Liquidity $ 545 $ 490

(a) In April 2021, the aggregate commitment of our lenders was reduced to $492 million based on the terms of our Revolving Credit Facility.

See Part I, Item 1 – Financial Statements, Note 5 Debt for more information on our Revolving Credit Facility.

Significant changes in oil and natural gas prices may have a material impact on our liquidity.

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Commodity Contracts

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 $63 million to enhance our liquidity.

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 through July 2021, as shown in the table below, to satisfy this requirement.

Our Revolving Credit Facility and our Second Lien Term Loan require us to maintain hedges on a notional amount of crude oil production as described in Part I, Item 1 – Financial Statements, Note 6 Debt.

We are currently in the process of entering into additional oil hedges to meet the hedging requirement in our credit agreements.

Our Revolving Credit Facility requires us to maintain hedges on a notional amount of crude oil production as described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report.

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.

At October 31, 2020, we had the following Brent-based crude oil contracts:

2021 July 2021

We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2021.

At April 30, 2021, we had the following Brent-based crude oil contracts:

2022 January - October 2023

Barrels per day 33,537 36,688 37,037 33,842 27,773 17,758

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• Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.

We also currently have Brent-based crude oil contracts for insignificant volumes through May 2021 which were entered into by our BSP JV and are included in our consolidated results but not in the above table.

The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021.

The hedges entered into by the BSP JV could affect the timing of the redemption of the BSP preferred interest.

• Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.

2021 Capital Program

Our capital program will be dynamic in response to oil market volatility while focusing on maintaining our oil production and strong liquidity and maximizing our free cash flow.

We entered 2021 with an internally funded capital program of $200 million to $225 million.

In March 2020, we reduced our capital investment to a level that maintains the mechanical integrity of our facilities to operate in a safe and environmentally responsible manner in response to the collapse in crude oil prices.

We made $37 million of internally funded capital investments in the first nine months of 2020 and we expect to invest an additional $10 million, primarily related to facilities, through the end of 2020.

At this level of investment, we suspended all internally funded drilling and most capital workovers and significantly reduced other activities.

The Board of Directors, which includes seven new directors appointed as of October 27, 2020, will review and determine our capital program for future periods.

Our JV partners invested $94 million in the first nine months of 2020.

On March 27, 2020, Alpine elected to suspend its funding obligations under the Alpine JV.

For further information, regarding the Alpine JV and its funding obligations, see the Development Joint Ventures section above.

The amounts in the table below reflect our consolidated capital investment, excluding changes in capital investment accruals, for the nine months ended September 30, 2020 and 2019:

Nine months ended

September 30,

(in millions)

Oil and natural gas $ 36 $ 325

Exploration — 9

Corporate and other 1 11

Total internally funded capital 37 345

BSP funded capital — 48

Total consolidated capital investment $ 37 $ 393

The curtailment of the development of our properties will lead to a decline in our production and may lower our reserves.

During the first quarter of 2021, the 2021 capital program was revised to $185 million to $210 million reflecting a reallocation of drilling capital to downhole maintenance, which provide efficiencies and faster payouts.

Our current plan anticipates we will gradually raise quarterly capital investment throughout the year.

If commodity prices decline significantly from current levels, we may need to adjust our capital program in response to market conditions.

Any curtailment of the development of our properties will lead to a decline in our production and may lower our reserves.

A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets.

Regulation of the Oil and Natural Gas Industry

In September 2020, the Ventura County Board of Supervisors adopted an amended General Plan and approved an associated Environmental Impact Report (EIR) that impose significant restrictions on new discretionary development projects in Ventura County.

With respect to new discretionary oil and gas development, the amended General Plan:

requires setbacks of 1,500 feet and 2,500 feet from residences and schools, respectively;

prohibits trucking of oil and produced water;

restricts flaring;

requires electrification of equipment;

and requires additional reviews for projects involving well stimulation treatment or steam injection.

Collectively, these restrictions would prevent or substantially reduce new development of at least five fields that we operate.

The Board is also considering a proposed ordinance to unilaterally revoke or revise longstanding conditional use permits, thereby applying the amended General Plan to fields with existing permits.

Multiple lawsuits have been filed challenging the amended General Plan and EIR, including by us, on numerous statutory and constitutional grounds.

Other government authorities have proposed or adopted new or more stringent requirements or restrictions on oil and gas operations and development, as described in the Regulatory section of our 2019 Form 10-K, and the Risk Factors in our 2019 Form 10-K and this Form 10-Q.

While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a material driver of changes in our quarterly results.

The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals (in millions):

2021 Target Three months ended March 31, 2021

(in millions)

Drilling $105 - $120 $ 13

Capital workovers 35 - 40 7

Infrastructure, corporate and other 45 - 50 7

Total $185 - $210 $ 27

Lawsuits, Claims, Commitments and Contingencies

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We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated.

Reserve balances at September 30, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates.

Reserve balances at March 31, 2021 and December 31, 2020 were not material to our condensed consolidated balance sheets as of such dates.

In October 2020, Signal Hill Services, Inc.

defaulted on its decommissioning obligations associated with two offshore platforms.

The Bureau of Safety and Environmental Enforcement determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with an approximately 35% share, are responsible for accrued decommissioning obligations associated with these offshore platforms.

Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy.

We are currently evaluating this claim.

We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters.

We believe that reasonably possible losses that we could incur in excess of reserves accrued would not be material to our consolidated financial position or results of operations.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases on July 15, 2020 automatically stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of us or our property to recover on, collect or secure a claim arising prior to July 15, 2020 or to exercise control over property of our bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such action or judicial or administrative proceeding.

Notwithstanding the general application of the automatic stay described above, government authorities may determine to continue actions brought under regulatory powers.

On October 13, 2020, the Bankruptcy Court confirmed our Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code , which was conditioned on certain items such as obtaining exit financing.

On October 27, 2020 the conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on the Effective Date.

Upon effectiveness of the Plan, the automatic stay discussed above no longer applies to ongoing judicial or administrative proceedings.

We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.

Significant Accounting and Disclosure Changes

See Part I, Item 1, Note 3 Accounting and Disclosure Changes for a discussion of new accounting matters.

See Part I, Item 1 – Financial Statements, Note 2 Accounting and Disclosure Changes for a discussion of new accounting matters.

Forward-Looking Statements

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• 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

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• 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

• the volatility of commodity prices and the potential for sustained low oil, natural gas and natural gas liquids 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, debt repurchases or changes to our capital plan

• insufficient cash flow to fund planned investments, interest payments on our debt, debt repurchases 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;

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• 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

• 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 (GHGs) 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;

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• changes in business strategy;

• PSC effects on production and unit production costs

• effect of stock price on costs associated with incentive compensation

• production-sharing contracts’ effects on production and unit operating costs;

• the effect of our stock price on costs associated with incentive compensation;

• effects of hedging transactions;

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• 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)

• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19;

• factors discussed in Item 1A, Risk Factors in our Annual Report on Form 10-K available at www.crc.com.

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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.

Item 3 Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, 2021, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the 2020 Annual Report.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis