California Resources Corp 10-Q

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations General Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries. We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We are incorporated in Delaware and became a publicly traded company on December 1, 2014. On July 15, 2020, we filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code and on October 27, 2020 we emerged from the Chapter 11 proceedings as further described below. Our condensed consolidated financial statements, including the Notes thereto, included in Part I, Item – Financial Statements have been prepared assuming we will continue as a going concern. We have applied Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852), in preparing these unaudited condensed consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the petition date (July 15, 2020), distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. As a result, we have segregated liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the Chapter 11 Cases and classified these items as liabilities subject to compromise (LSTC) on our condensed consolidated balance sheet as of September 30, 2020. In addition, we have classified all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Cases subsequent to the petition date as reorganization items, net in our condensed consolidated statement of operations for the period ended September 30, 2020. Further, we believe that we are required to adopt fresh start accounting upon emergence from bankruptcy because (1) the holders of existing voting shares prior to emergence received less than 50% of our new voting shares following our emergence from bankruptcy and (2) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, which are included in liabilities subject to compromise. Fresh start accounting will be applied as of October 27, 2020, the date we emerged from bankruptcy. Under the principles of fresh start accounting, a new reporting entity is considered to have been created, and, as a result, the reorganization value of the emerging entity is assigned to individual assets and liabilities based on their estimated relative fair values. The process of estimating the fair value of our assets, liabilities and equity upon emergence is currently ongoing. In support of the Plan, the enterprise value of the successor company was estimated and approved by the Bankruptcy Court to be in the range of $2.2 billion to $2.8 billion. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements of the successor entity will not be comparable to the financial statements, including this statement, prepared prior to our Effective Date. Chapter 11 Proceedings Our spin–off from Occidental Petroleum Corporation (Occidental) on November 30, 2014 burdened us with significant debt which was used to pay a $6.0 billion cash dividend to Occidental. Together with the activity level and payables that we assumed from Occidental and due to Occidental's retention of the vast majority of our receivables, our debt peaked at approximately $6.8 billion in May 2015. Since then, we have engaged in a series of asset sales, joint ventures, debt exchanges, tenders, debt repurchases and other financing transactions to reduce our overall level of debt and improve our balance sheet prior to filing for bankruptcy. As of September 30, 2020, we had outstanding net long-term debt of approximately $5.1 billion, of which $4.4 billion is presented as liabilities subject to compromise on our condensed consolidated balance sheet. On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 Cases were jointly administered under the caption In re California Resources Corporation, et al. , Case No. 20-33568 (DRJ). We filed with the Bankruptcy Court, on July 24, 2020, the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code and, on October 8, 2020, the Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as amended, supplemented or modified, the Plan ). On October 13, 2020, the Bankruptcy Court confirmed the Plan, which was conditioned on certain items such as obtaining exit financing. The conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on October 27, 2020 (Effective Date). 34 During the course of the Chapter 11 Cases, the Bankruptcy Court granted the relief requested in certain motions, authorizing payments of pre-petition liabilities with respect to certain employee compensation and benefits, taxes, royalties, certain essential vendor payments and insurance and surety obligations, which allowed our business operations to continue uninterrupted during the pendency of the Chapter 11 Cases. All transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court. On July 15, 2020, immediately prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares Management L.P. (Ares), including ECR Corporate Holdings L.P., a portfolio company of Ares (ECR), entered into a Settlement and Assumption Agreement (Settlement Agreement) related to our midstream joint venture, Elk Hills Power, LLC (Ares JV or Elk Hills Power), which holds our Elk Hills power plant and a cryogenic gas processing plant. On August 25, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on a final basis. Among other things, the Settlement Agreement included a conversion right, which would be deemed exercised upon our emergence from bankruptcy, allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by ECR in exchange for secured notes (EHP Notes), approximately 20.8% of our new common stock (Ares Settlement Stock) and $2.5 million in cash. For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 7 Joint Ventures. The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following agreements: (i) Credit Agreement, dated as of September 24, 2014, among JPMorgan Chase Bank, N.A., as administrative agent, and the lenders that are party thereto (2014 Revolving Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The Bank of New York Mellon Trust Company, N.A., as collateral and administrative agent, and the lenders that are party thereto (2016 Credit Agreement), (iii) Credit Agreement, dated as of November 17, 2017, among The Bank of New York Mellon Trust Company, N.A., as administrative agent, and the lenders that are party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes and together with the 5% Senior Notes due 2020 and 2021 Notes, the Senior Notes). Additionally, other events of default, including cross-defaults, are present under these debt agreements. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against us, including exercising remedies as a result of any event of default. See Part I, Item 1 – Financial Statements, Note 6 Debt for additional details about our debt. Joint Plan of Reorganization Under Chapter 11 Pursuant to the Plan, the following transactions occurred on the Effective Date: • We issued an aggregate of 83.3 million shares of new common stock and reserved 4.4 million shares for issuance upon exercise of the warrants described below; • We acquired all of the member interests in the Ares JV held by ECR in exchange for the EHP Notes, 17.3 million shares of new common stock and $2.5 million in cash (see Part I, Item 1 – Financial Statements, Note 6 Debt and Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information); • Holders of secured claims under the 2017 Credit Agreement received 22.7 million shares of new common stock in exchange for those claims, and holders of deficiency claims under the 2017 Credit Agreement and all outstanding obligations under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received 4.4 million shares of new common stock in exchange for those claims; • In connection with the Subscription Rights offering and Backstop Commitment Agreement, 34.6 million shares of new common stock were issued in exchange for $446 million (net of a $4 million fee), the proceeds of which were used to pay down our debtor-in-possession financing; • Our Subscription Rights offering was backstopped by certain creditors who received 3.5 million shares of new common stock as a backstop commitment premium (refer to Part I, Item 1 – Financial Statements, Note 16 Equity for additional information on the backstop commitment premium); • The holders of Unsecured Debt Claims (as defined in the Plan) under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received Tier 1 Warrants and Tier 2 Warrants (each as defined in the Plan and collectively, Warrants) to purchase up to 2% and 3%, respectively, of our outstanding shares (on a fully diluted basis calculated immediately after the Effective Date), with an initial exercise price of $36.00 per share, which expire on October 27, 2024 and have customary anti-dilution protections (refer to Note 16 Equity for additional information on the Warrants); • All other general unsecured claims will be paid or disputed in the ordinary course of business; and • All existing equity interests were cancelled and their holders received no distributions. 35 As a condition to our emergence, we repaid the outstanding balance of our debtor-in-possession financing with proceeds from our Subscription Rights offering, Backstop Commitment Agreement and a new senior secured revolving credit facility led by Citibank, N.A. We also issued approximately 821,000 shares of new common stock for a junior debtor-in-possession exit fee. For more information on our debtor-in-possession credit agreements and our post-emergence indebtedness, see Part I, Item 1 – Financial Statements, Note 6 Debt . Additionally, pursuant to our Plan, our post-emergence Board of Directors consists of nine directors as follows: (i) our President and Chief Executive Officer, Todd A. Stevens, (ii) seven non-employee directors, including Douglas E. Brooks, Tiffany (TJ) Thom Cepak, James N. Chapman, Mark A. McFarland, Julio M. Quintana, William B. Roby and Brian Steck, and (iii) one vacancy which will be filled by our post-emergence Board of Directors in accordance with our charter and bylaws. The seven non-employee directors were all appointed to the Board of Directors on October 27, 2020. Our Board of Directors has determined that Ms. Cepak and Messrs. Brooks, Chapman, McFarland, Quintana, Roby and Steck are independent directors as that term is defined in the listing standards of the New York Stock Exchange (NYSE). Mr. Stevens is not considered by our Board of Directors to be independent because of his current employment with CRC. Changes to our Stock-Based Compensation Programs As a result of our bankruptcy, the outstanding stock-based awards under our Amended and Restated California Resources Corporation Long-Term Incentive Plan were cancelled on our Effective Date. Any new stock-based awards or compensation plans will be reviewed and approved by our Board of Directors, which includes seven new directors appointed on October 27, 2020. The cancellation of these stock-based compensation awards resulted in the recognition of all previously unrecognized compensation expense for equity-settled awards and the liability related to our cash-settled awards was eliminated as the participants received no consideration. The net effect of these adjustments was not material to our financial statements. Changes to the 2020 Compensation Programs in Second Quarter 2020 In the second quarter of 2020, resulting from the unprecedented circumstances affecting the industry and market volatility, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately aligned compensation opportunities with our 2020 goals and ensured the stability of our workforce. Following this review, effective May 19, 2020, our then Board of Directors approved changes in the variable compensation programs for all participating employees. The previously established target amounts of 2020 variable compensation programs did not change; however, all amounts that vest are being settled in cash. As a condition to receiving any award, participants waived participation in our 2020 annual incentive program and forfeited all stock-based compensation awards previously granted in 2020. At that time, there were no changes to stock-based compensation awards granted prior to February 2020; however, these pre-2020 awards were subsequently cancelled as part of the Plan. Changes to the variable compensation programs had the effect of accelerating the associated payments into 2020 from future periods. However, the total amount of compensation to be paid under the variable compensation programs at target for 2020 remained largely the same as the amounts that would have been paid at target prior to the changes. Our future compensation programs will be determined by our new Board of Directors. Organizational Changes During the course of the Chapter 11 Cases, we evaluated the structure of our workforce and, in August 2020, we implemented organizational changes that resulted in a reduction of our headcount from 1,250 to approximately 1,100 employees. We believe the steps taken improved and strengthened our business as we emerge from bankruptcy. We recorded a one-time $10 million restructuring charge in the third quarter of 2020. We will continue to evaluate resource levels depending on commodity prices. Business Environment and Industry Outlook 36 Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly as a result of numerous market-related variables , especially given current global geopolitical and economic conditions. These and other factors make it impossible to predict realized prices reliably. Prices for oil and gas products in 2020 have been strongly influenced by the Coronavirus Disease 2019 (COVID-19) pandemic and by the actions of foreign producers. The COVID-19 pandemic caused an unprecedented demand collapse due to global shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices. In addition , members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia agreed to carry out record oil production cuts in April 2020 to be followed by gradual incremental increases in multiple steps. In the summer of 2020, OPEC and Russia moved ahead with the first hike in crude oil output. The next hike in crude oil output is currently scheduled for January 2021. As a result of these conditions, the Brent oil price has been trading in a narrow range around $40 per barrel for several months. Reduced demand initially caused shortages in available storage facilities globally and required many oil and gas producers to shut-in wells or curtail production. In April 2020, oil prices declined precipitously, temporarily reaching negative values for spot West Texas Intermediate (WTI) crude. From May 2020 through August 2020, oil prices began to recover as inventory levels stabilized and an easing of shelter-in-place restrictions created partial demand recovery. Prices declined again slightly in September 2020 as demand for oil dropped due to an increase in COVID-19 cases around the world. Demand and pricing may decline again due to a resurgence in the number of cases globally and across parts of the United States, which could result in the re-imposition of certain restrictions. The current futures forward curve for Brent crude indicates that prices may continue at close to current levels, which are significantly lower than pre-pandemic levels, for an extended period of time. We continue to closely monitor the impact of COVID-19, which negatively impacted our business and results of operations beginning in the first quarter of 2020. The extent to which our total year operating results will be impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning potential vaccines, a resurgence of the pandemic and actions taken to contain it or actions taken by government authorities or other producers in response to commodity price movements, among other things. See Part II, Item 1A – Risk Factors , below for further discussion regarding the impact of the pandemic and declines in commodity prices. The following table presents the average daily Brent, WTI and NYMEX prices for the three and nine months ended September 30, 2020 and 2019: Three months ended September 30, Nine months ended September 30, 2020 2019 2020 2019 Brent oil ($/Bbl) $ 43.37 $ 62.00 $ 42.53 $ 64.74 WTI oil ($/Bbl) $ 40.93 $ 56.45 $ 38.32 $ 57.06 NYMEX gas ($/MMBtu) $ 1.93 $ 2.27 $ 1.92 $ 2.72 Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units. Operations Response to COVID-19 Pandemic and Industry Downturn We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity. 37 In response to the rapid fall in commodity prices in March 2020, we reduced our 2020 capital budget to a level that maintains the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner and ceased all field development and growth projects. As a result, our internally funded capital was $7 million in the second and third quarters of 2020. We also monetized all of our crude oil hedges in March 2020, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to enhance our liquidity. We began shutting in high cost, negative margin wells in March 2020 to reduce operating costs and enhance cash flow which curtailed average net production volumes by approximately 5 MBoe/d and 3 MBoe/d for the second and third quarters of 2020, respectively. As part of our operational efficiency measures, we evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs. Our teams utilized our extensive automation controls, monitored weekly well margins, and made temporary adjustments to our producing wells to ensure our operations aligned with the price environment. As a result of these actions, as well as further cost rationalization and streamlining efforts coupled with lower activity levels, our third quarter 2020 average operating expense run rate is below $50 million per month compared to the first quarter of 2020 average of $64 million per month. At our current level of capital investment and surface activity levels, production could continue to decline at a moderate pace through the remainder of the year. We have also implemented various measures to protect the health of our workforce and to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. These initiatives were in accordance with the orders and guidance of federal, state and local authorities to mitigate the risks of the disease and included temporarily closing all our administrative offices and implementing remote working for most office employees. As a result, our management team and substantially all of our office personnel worked remotely beginning in March 2020. In June 2020, we began a phased return to the office, focused on those employees for whom remote work was not feasible. In addition, in April 2020, we implemented reduced work hours for nearly all of our office employees and reduced salaries for our management team, in each case on a temporary basis that ended in May 2020. In August 2020, we implemented organizational and operational efficiencies that resulted in a reduction of our headcount to approximately 1,100 employees. These actions were made in an effort to preserve liquidity after the deterioration of commodity prices following the outbreak of COVID-19. Our operational employees and contractors and certain support personnel have been classified as an essential critical infrastructure workforce by government authorities. Accordingly, they worked through the shutdowns and continue to work in their plant, rig, field and office locations under our COVID-19 Health and Safety Plan that includes protocols for reporting of illness, self-quarantine, hygiene, applying social distancing to minimize close contact between workers, cleaning or disinfection of workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce. Our Operations We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. We are the largest non-governmental oil and natural gas mineral acreage holder in California, with interests in 2.1 million net mineral acres, approximately 60% of which is held in fee and 17% is held by production. Our oil and gas leases have primary terms ranging from one to ten years. Once production commences, the leases are typically extended on the producing acreage through the end of their producing life. As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells while retaining our oil and gas leases which are held by production. We also own or control a network of integrated infrastructure that complements our operations including gas processing plants, oil and gas gathering systems, power plants and other related assets. Our strategically located infrastructure helps us maximize the value generated from our production. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and gas reserves we can economically produce over the longer term. With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing carbon capture and sequestration, renewable energy opportunities, agricultural activities and other commercial uses. 38 Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and production costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and production costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and production costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 17% of our net production for the three months ended September 30, 2020. In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our revenue, general and administrative and operating costs and has no effect on our net results. We own a large and geographically diverse portfolio of assets that generate the following revenue streams: Crude Oil — We sell nearly all of our crude oil into the California refining markets, which offer relatively favorable pricing for comparable grades relative to other U.S. regions. Substantially all of our crude oil production is connected, via our gathering systems, to third-party pipelines and California refining markets and we have not encountered any significant issues with storage or reaching these markets during the industry downturn. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements. California is heavily reliant on imported sources of energy, with approximately 72% of oil and 90% of natural gas consumed in 2019 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. We continue to receive a premium in comparison to other comparable grades due to the demand for our product in the state of California. We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades. Natural Gas — We sell all of our natural gas not used in our operations into the California markets on a monthly basis at market-based index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity from producing areas. Transportation capacity influences prices because California imports approximately 90% of its natural gas from other states and Canada. As a result, we typically enjoy favorable pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and even a smaller percentage of our revenue is from natural gas. In addition to selling natural gas, we also use natural gas for our steamfloods and power generation. As a result, the positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to higher revenue. Conversely, lower natural gas prices lower the operating costs but have a net negative effect on our financial results. We currently have sufficient firm transportation capacity contracts to transport our natural gas, where some capacity volumes vary by month. We sell virtually all of our natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis. 39 Natural Gas Liquid (NGL) — NGL price realizations are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints and seasonality can magnify pricing volatility. Our earnings are also affected by the performance of our complementary processing and power-generation assets. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Our natural gas processing plants also facilitate access to third-party delivery points near the Elk Hills field. We currently have a pipeline delivery contract to transport 6,500 barrels per day of NGLs to market. Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually delivered. In connection with another pipeline delivery contract that we assumed from Occidental, we made a one-time deficiency payment of $20 million in April 2020 when the contract expired. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 33% of our NGLs are sold to export markets. Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces operating costs and increases reliability. We sell the excess electricity generated to a local utility, other third parties and the grid. The power sold to the utility is subject to agreements through the end of 2023, which include a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Any excess capacity not sold to other third parties is sold to the grid. The prices obtained for excess power impact our earnings but generally by an insignificant amount. Derivatives and Hedging Activities We opportunistically seek strategic hedging transactions to help protect our cash flow, operating margin and capital program from both the cyclical nature of commodity prices and interest rate movements while maintaining adequate liquidity and improving our ability to comply with our debt covenants. We can give no assurance that our hedging programs will be adequate to accomplish our objectives. The Senior DIP Credit Agreement required us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. On July 24, 2020, we entered into various derivative instruments to satisfy this requirement. Our post-emergence Revolving Credit Facility and Second Lien Term Loan require us to maintain hedges on a higher amount of crude oil production as described in Part I, Item 1 – Financial Statements, Note 6 Debt. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges. Development Joint Ventures We have a number of joint ventures that have allowed us to accelerate the development of our assets, which provided us with operational and financial flexibility as well as near-term production benefits. The following table summarizes the cumulative investment through September 30, 2020 by our development joint venture partners, before transaction costs: Cumulative Investment through September 30, 2020 (in millions) Alpine $ 227 Royale 17 MIRA 139 BSP 200 Total Capital Investment $ 583 40 For more information on our development joint ventures, please see our most recent Form 10-K for the year ended December 31, 2019. Alpine JV In July 2019, we entered into a development agreement with Alpine Energy Capital, LLC (Alpine). Alpine has committed to invest $320 million, which may be increased to a total investment of $500 million subject to the mutual agreement of the parties. The initial $320 million commitment covers multiple development opportunities and is intended to be invested over a period of up to three years in accordance with a 275-well development plan. On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below $45 per barrel over a 30-trading day period. The suspension may be lifted by mutual consent. As of September 30, 2020, funding for the initial development phase has not re-started. Midstream Joint Venture Ares JV In February 2018, our wholly-owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream JV with ECR, a portfolio company of Ares. The Ares JV holds the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. On the Effective Date, as required by the Note Purchase Agreement, CREH transferred its ownership of two low temperature separation plants located at the Elk Hills field to Elk Hills Power. Prior to our Effective Date, we held 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR held 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. The Ares JV was required to distribute each month its excess cash flow over its working capital requirements first to the Class B holders and then to the Class C common interests, on a pro-rata basis. As contemplated by the terms of the JV, CREH purchased electricity and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which were used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC. CREH also served as the operator of the Ares JV and provided operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement. These agreements became intercompany agreements on the Effective Date and were cancelled as described below. As described above in Business Environment and Outlook and Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings , we entered into the Settlement Agreement with ECR and Ares which, among other things, changed the liquidation preference for the Class B member interest to $835 million, decreased the preferred return from 13.5% per annum to 9.5% per annum payable at the end of each month, removed the liquidation premium for the Class A common interest and removed the payment of any previously accrued but unpaid preferred distributions plus a make-whole payment that ECR, as the holder of the Class B preferred interests, would otherwise have been entitled to in the event of a redemption transaction. The Settlement Agreement granted us the right (Conversion Right) to acquire all (but not less than all) of the equity interests of Elk Hills Power owned by ECR in exchange for the EHP Notes, Ares Settlement Stock and $2.5 million in cash. The Conversion right was deemed to have been exercised on the Effective Date. Although certain provisions in the Settlement Agreement were not effective until certain conditions were met, such as the Bankruptcy Court entering a final order, we determined that the amended terms were substantively different such that the existing Class A common, Class B preferred and Class C common member interests held by ECR were treated as redeemed in exchange for new member interests issued at fair value. The estimated fair value of the new member interests was lower than the carrying value of the existing member interests by $138 million. In accordance with GAAP, the return from noncontrolling interest holders was recorded to additional paid-in capital on our condensed consolidated balance sheet as of September 30, 2020. However as required by GAAP, the return is included in our earnings per share calculations. See Part I, Item 1 – Financial Statements, Note 10 Earnings per Share for adjustments to net income (loss) attributable to common stock which include a return from noncontrolling interests. 41 We were deemed to have exercised the Conversion Right on the Effective Date and we issued the EHP Notes in the aggregate principal amount of $300 million, Ares Settlement Stock comprising approximately 20.8% (subject to dilution) of the new common stock (Conversion) and $2.5 million in cash. Upon the Conversion, Elk Hills Power became an indirect wholly-owned subsidiary, and Ares and its affiliates ceased to have any direct or indirect interest in Elk Hills Power, other than any interest Ares may have indirectly through its interests in the EHP Notes and Ares Settlement Stock. In connection with the Conversion, Elk Hills Power’s limited liability company agreement was amended and restated. In connection with the Conversion, on the Effective Date, we entered into a Sponsor Support Agreement dated the Effective Date (Support Agreement) pursuant to which, among other things, the parties agreed that Elk Hills Power will be our primary provider of electricity to, and will be the primary processor of our natural gas produced from, the Elk Hills field, which is already consistent with our current practice. On the Effective Date, in connection with the Conversion, we terminated: (a) the Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH and (b) the Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH. For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 7 Joint Ventures. For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 1 Chapter 11 Proceedings. Fixed and Variable Costs Our production costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. As a result of the measures taken to address the recent industry downturn, we have demonstrated that we can significantly reduce our operating costs in response to prevailing market conditions. As a result, we continue to believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs. When we see growth in a field, we increase capacities and, similarly, when a field nears the end of its economic life, we manage the costs while it remains economically viable to produce. 42 Production and Prices The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three and nine months ended September 30, 2020 and 2019: Three months ended September 30, Nine months ended September 30, 2020 2019 2020 2019 Oil (MBbl/d) San Joaquin Basin 40 51 42 53 Los Angeles Basin 22 24 25 24 Ventura Basin 2 4 3 4 Total 64 79 70 81 NGLs (MBbl/d) San Joaquin Basin 14 16 14 15 Ventura Basin — — — 1 Total 14 16 14 16 Natural gas (MMcf/d) San Joaquin Basin 142 162 148 163 Los Angeles Basin 2 2 2 2 Ventura Basin 4 4 4 6 Sacramento Basin 20 28 21 29 Total 168 196 175 200 Total Net Production (MBoe/d) 106 128 113 130 Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. For the three months ended September 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 22 MBoe/d or 17%. The decrease in production related to higher downtime caused by significantly reduced well repair work, as well as the temporary shut-in of certain wells beginning in March 2020, which negatively impacted our net production for the three months ended September 30, 2020 by 3 MBoe/d compared to the same prior-year period. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the third quarter of 2020 by approximately 1 MBoe/d compared to the same period in 2019. Excluding the effects of shut-in production and PSC-type contracts, our base decline was still in line with our previously disclosed rate of low to mid-teens, which largely resulted from low internal capital investment and well repair work. For the nine months ended September 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 17 MBoe/d or 13%. The decrease in production related to higher downtime caused by significantly reduced well repair work, as well as the temporary shut-in of certain wells beginning in March 2020, and the effect of the May 2019 partial divestiture of the Lost Hills field, which negatively impacted our net production for the nine months ended September 30, 2020 by 3 MBoe/d compared to the same prior-year period. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the nine months of 2020 by 3 MBoe/d compared to the same period in 2019. Excluding the effects of the Lost Hills transaction, shut-in production and PSC-type contracts, our base decline was still in line with our previously disclosed rate of low to mid-teens, which largely resulted from low internal capital investment and well repair work. With an ongoing gradual increase of well repair work, we believe our base decline rate going forward will gradually return to the low to mid-teens. 43 The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three and nine months ended September 30, 2020 and 2019: Three months ended September 30, 2020 2019 Price Realization Price Realization Oil ($ per Bbl) Brent $ 43.37 $ 62.00 Realized price without hedge $ 41.83 96% $ 62.85 101% Settled hedges 0.32 5.56 Realized price with hedge $ 42.15 97% $ 68.41 110% WTI $ 40.93 $ 56.45 Realized price without hedge $ 41.83 102% $ 62.85 111% Realized price with hedge $ 42.15 103% $ 68.41 121% NGLs ($ per Bbl) Realized price (% of Brent) $ 25.16 58% $ 23.55 38% Realized price (% of WTI) $ 25.16 61% $ 23.55 42% Natural gas NYMEX ($/MMBtu) $ 1.93 $ 2.27 Realized price without hedge ($/Mcf) $ 2.22 115% $ 2.73 120% Settled hedges 0.02 (0.01) Realized price with hedge ($/Mcf) $ 2.24 116% $ 2.72 120% Nine months ended September 30, 2020 2019 Price Realization Price Realization Oil ($ per Bbl) Brent $ 42.53 $ 64.74 Realized price without hedge $ 41.27 97% $ 65.03 100% Settled hedges 2.00 3.13 Realized price with hedge $ 43.27 102% $ 68.16 105% WTI $ 38.32 $ 57.06 Realized price without hedge $ 41.27 108% $ 65.03 114% Realized price with hedge $ 43.27 113% $ 68.16 119% NGLs ($ per Bbl) Realized price (% of Brent) $ 25.17 59% $ 31.04 48% Realized price (% of WTI) $ 25.17 66% $ 31.04 54% Natural gas NYMEX ($/MMBtu) $ 1.92 $ 2.72 Realized price without hedge ($/Mcf) $ 2.05 107% $ 2.82 104% Settled hedges 0.06 (0.01) Realized price with hedge ($/Mcf) $ 2.11 110% $ 2.81 103% 44 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) Cash $ 122 $ 17 Trade receivables $ 155 $ 277 Inventories $ 61 $ 67 Other current assets, net $ 82 $ 130 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. 45 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. 46 Statements of Operations Analysis 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: Three months ended September 30, Nine months ended September 30, 2020 2019 2020 2019 Production costs $ 14.52 $ 18.82 $ 14.85 $ 19.32 Production costs, excluding effects of PSC-type contracts (a) $ 13.37 $ 17.44 $ 14.03 $ 17.82 Field general and administrative expenses (b) $ 1.34 $ 1.19 $ 1.16 $ 1.24 Field depreciation, depletion and amortization (b) $ 8.03 $ 9.28 $ 8.68 $ 9.38 Field taxes other than on income (b) $ 3.40 $ 2.73 $ 3.10 $ 2.60 (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. 47 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: Three months ended September 30, Nine months ended September 30, 2020 2019 2020 2019 (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 Electricity sales 43 38 75 88 Other revenue 4 3 12 17 Production costs (141) (221) (460) (684) General and administrative expenses (64) (66) (193) (228) Depreciation, depletion and amortization (89) (118) (296) (357) Asset impairments — — (1,736) — Taxes other than on income (42) (42) (121) (119) Exploration expense (2) (5) (9) (25) Marketing and trading costs (35) (45) (67) (170) Electricity cost of sales (17) (18) (47) (51) Transportation costs (10) (10) (31) (30) Other expenses, net (22) (8) (75) (33) Reorganization items, net 66 — 66 — Interest and debt expense, net (28) (95) (200) (293) Net gain on early extinguishment of debt — 82 5 108 Other non-operating expenses (32) (8) (93) (18) (Loss) income before income taxes (7) 127 (1,999) 124 Income tax — — — — 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 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. 48 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. 2019 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: Oil NGLs Natural Gas Total (in millions) Three months ended September 30, 2019 $ 457 $ 34 $ 50 $ 541 Changes in realized prices (153) 2 (12) (163) Changes in production (58) (4) (4) (66) Three months ended September 30, 2020 $ 246 $ 32 $ 34 $ 312 Note: 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, 2020 2019 (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 49 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, 2020 2019 (in millions) Production costs $ 141 $ 221 Exclude: Stock-based compensation — 1 Exclude: 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. Three months ended September 30, 2020 2019 (in millions) G&A expenses $ 64 $ 66 Exclude: Stock-based compensation (1) (1) Exclude: Other employee incentive awards (19) (9) Exclude: 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. 50 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 Note: 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. 51 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. 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. Nine months ended September 30, 2020 2019 (in millions) Non-cash derivative loss, excluding noncontrolling interest $ (31) $ (99) Non-cash derivative gain, noncontrolling interest 1 — Total non-cash changes (30) (99) 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, 2020 2019 (in millions) Production costs $ 460 $ 684 Exclude: Stock-based compensation — (7) Exclude: Other employee incentive awards (17) (18) Production costs, excluding employee incentive compensation $ 443 $ 659 52 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, 2020 2019 (in millions) G&A expenses $ 193 $ 228 Exclude: Stock-based compensation (3) (21) Exclude: Other employee incentive awards (42) (30) Exclude: 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. 53 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. 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 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. 54 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. 55 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, 2020 2019 (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 56 Liquidity and Capital Resources Cash Flow Analysis – Pre-Emergence Nine months ended September 30, 2020 2019 (in millions) Cash flow from operating activities $ 141 $ 540 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 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. 57 Liquidity 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. 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; and • 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 $18 million per year, which is our required minimum distribution to BSP. 58 The following table presents our pro forma capitalization after giving effect to certain transactions in the Plan, assuming our Effective Date was on September 30, 2020 (a) : Actual September 30, 2020 Reorganization Adjustments Pro Forma ($ in millions) Senior DIP Facility $ 83 $ (83) $ — Junior DIP Facility 650 (650) — Total short-term borrowings 733 (733) — Revolving Credit Facility — 225 225 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 100 (100) — 6% Senior Notes due 2024 144 (144) — 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. Derivatives Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. To mitigate some of the risk inherent in the downward movement in oil prices, we may enter into various derivative instruments to hedge commodity price risk. 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. 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. 59 At October 31, 2020, we had the following Brent-based crude oil contracts: Q4 2020 Q1 2021 Q2 2021 July 2021 Sold Calls: Barrels per day 4,800 4,500 4,500 4,200 Weighted-average price per barrel $ 48.05 $ 48.05 $ 48.05 $ 48.05 Purchased Puts: Barrels per day 18,600 18,000 9,000 8,400 Weighted-average price per barrel $ 44.84 $ 45.00 $ 40.00 $ 40.00 Sold Puts: Barrels per day 13,800 13,500 4,500 4,200 Weighted-average price per barrel $ 36.52 $ 36.67 $ 30.00 $ 30.00 Swaps: Barrels per day 6,400 6,000 6,000 5,600 Weighted-average price per barrel $ 44.75 $ 44.75 $ 44.75 $ 44.75 The outcomes of the derivative positions are as follows: • Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel. • Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel. • Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel. 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. 60 2020 Capital Program We entered 2020 with an internally funded capital program of $100 million to $300 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, 2020 2019 (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. 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. Seasonality 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. 61 Lawsuits, Claims, Commitments and Contingencies We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. 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. 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. Significant Accounting and Disclosure Changes See Part I, Item 1, Note 3 Accounting and Disclosure Changes for a discussion of new accounting matters. 62 Forward-Looking Statements The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our future: • financial position, liquidity, cash flows and results of operations • business prospects • transactions and projects • operating costs • Value Creation Index (VCI) metrics, which are based on certain estimates including future production rates, costs and commodity prices • operations and operational results including production, hedging and capital investment • budgets and maintenance capital requirements • reserves • type curves • expected synergies from acquisitions and joint ventures Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include: • our ability to execute our business plan post-emergence • the volatility of commodity prices and the potential for sustained low oil, natural gas and NGL prices • impact of our recent emergence from bankruptcy on our business and relationships • debt limitations on our financial flexibility • insufficient cash flow to fund planned investments, 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 • limitations on transportation or storage capacity and the need to shut-in wells • inability to enter into desirable transactions, including acquisitions, asset sales and joint ventures • our ability to utilize our net operating loss carryforwards to reduce our income tax obligations • limitations on the liquidity of our new common stock and volatility of its market price • legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products • joint ventures and acquisitions and our ability to achieve expected synergies • the recoverability of resources and unexpected geologic conditions • incorrect estimates of reserves and related future cash flows and the inability to replace reserves • changes in business strategy • PSC effects on production and unit production costs • effect of stock price on costs associated with incentive compensation • effects of hedging transactions • equipment, service or labor price inflation or unavailability • availability or timing of, or conditions imposed on, permits and approvals • lower-than-expected production, reserves or resources from development projects, joint ventures or acquisitions, or higher-than-expected decline rates • disruptions due to accidents, mechanical failures, power outages, transportation or storage constraints, natural disasters, labor difficulties, cyber-attacks or other catastrophic events • pandemics, epidemics, outbreaks, or other public health events, such as the coronavirus disease (COVID-19) • factors discussed in Item 1A, Risk Factors in our Annual Report on Form 10-K available at www.crc.com. 63 Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 64