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 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. These financial statements do not include any adjustments that might result from the outcome of our going concern uncertainty or the Chapter 11 Cases (as defined below). There is substantial doubt that we can continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases as discussed below. Further, the Chapter 11 Cases could result in a change in the basis of our accounting, which may have a material effect on the carrying value of certain assets and liabilities. Business Environment and Industry Outlook Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly as a result of numerous market-related variables , especially given current global geopolitical and economic conditions. These and other factors make it impossible to predict realized prices reliably. Prices for oil and gas products in the first half of 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 the 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 did not extend existing oil production cuts expiring on April 1, 2020, and Saudi Arabia and Russia announced significant increases in crude oil production. The unprecedented dual impact of a severe global oil demand decline due to the COVID-19 pandemic repercussions coupled with a substantial increase in supply from Saudi Arabia and Russia resulted in a collapse in crude oil prices. Reduced demand caused shortages in available storage facilities globally and required many oil and gas producers to shut in wells or curtail production. In April 2020, oil prices continued to decline precipitously temporarily reaching negative values for spot WTI crude. In May 2020 and June 2020, oil prices began to recover as producers across the world, including OPEC, Russia, the United States and others started cutting their production levels sharply and announced significant capital reductions , and an easing of shelter-in-place restrictions created partial demand recovery. However, demand and pricing may again decline due to the resurgence of the outbreak across parts of the United States and related re-imposition of certain restrictions. The current futures forward curve for Brent crude indicates that prices may continue at close to current levels but 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 lower commodity prices have continued into the second quarter and are currently expected to remain depressed for an extended period of time based on current futures curves. The extent to which our total year operating results will be impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning potential vaccines, the severity 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. 26 The following table presents the average daily Brent, WTI and NYMEX prices for the three and six months ended June 30, 2020 and 2019: Three months ended June 30, Six months ended June 30, 2020 2019 2020 2019 Brent oil ($/Bbl) $ 33.27 $ 68.32 $ 42.12 $ 66.11 WTI oil ($/Bbl) $ 27.85 $ 59.82 $ 37.01 $ 57.36 NYMEX gas ($/MMBtu) $ 1.77 $ 2.66 $ 1.91 $ 2.95 Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units. Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code In light of our significant indebtedness and the unprecedented impact to our financial position resulting from the commodity price environment and the COVID-19 pandemic, combined with continued challenging conditions in the credit and capital markets, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court) on July 15, 2020. The Chapter 11 cases filed by us (Chapter 11 Cases) are being jointly administered under the caption In re California Resources Corporation, et al. , Case No. 20-33568 (DRJ). On July 24, 2020, we filed a Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court. We continue to operate our business as “debtors-in-possession” (DIP) under the jurisdiction of the Bankruptcy Court and in accordance with the Bankruptcy Code. To ensure our ability to continue operating in the ordinary course of business and to minimize the effect of the Chapter 11 Cases on our employees, vendors and customers, we filed motions for customary “first day” relief with the Bankruptcy Court. On July 17, 2020, the Bankruptcy Court entered interim or final orders that included 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. On July 21, 2020, the Bankruptcy Court approved on a final basis an order designed to assist us in preserving certain tax attributes. This order established the procedures that certain stockholders and potential stockholders will be required to comply with regarding transfers of, or declarations of worthlessness with respect to, our common stock as well as certain notice obligations. On July 22, 2020, the Bankruptcy Court approved on an interim basis a motion authorizing us to enter into DIP financing. The commencement of the Chapter 11 Cases constitutes 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 America 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). Additionally, other events of default, including cross-defaults, are present under these debt agreements. Under the Bankruptcy Code, the creditors under these debt agreements are 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 5 Debt for additional details about our debt. Restructuring Support Agreement On July 15, 2020, we entered into a Restructuring Support Agreement which was subsequently amended on July 24, 2020 (RSA). This RSA contemplates a restructuring plan that establishes a reorganized company with a new capital structure. The transactions contemplated by the RSA plan include (i) entering into a senior secured superpriority DIP credit facility (Senior DIP Facility) in an aggregate principal amount of up to approximately $483 million, (ii) entering into a junior secured superpriority DIP term loan facility in an aggregate amount of $650 million (Junior DIP Facility), (iii) the implementation of financing upon emergence from bankruptcy, (iv) the issuance of new common stock, and (v) a $450 million equity rights offering, backstopped by certain parties to the RSA. 27 The following creditors have entered into the RSA: (i) lenders holding approximately 85% of the outstanding principal amount of loans under the 2017 Credit Agreement, (ii) creditors holding approximately 68% of the aggregate claims arising under the 2016 Credit Agreement, the Second Lien Notes, the 2021 Notes and the 2024 Notes, and (iii) one or more funds, investment vehicles and/or accounts managed or advised by Ares Management LLC (Ares) or its affiliates, including ECR Corporate Holdings L.P. (ECR). The transactions contemplated by the RSA, if approved, will result in current holders of our common stock receiving no distribution on account of their claims or interests. No assurance can be given that the Bankruptcy Court will approve the terms proposed under the RSA. Debtor-in-Possession Credit Agreements On July 23, 2020, we entered into (1) a Senior Secured Superpriority DIP Credit Agreement with JPMorgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement) and (2) a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement). For more information on our debtor-in-possession credit agreements, see Part I, Item 1 – Financial Statements, Note 5 Debt and Liquidity and Capital Resources below. Ares JV Settlement Agreement On July 15, 2020, prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares, including ECR, entered into a settlement and assumption agreement (Settlement Agreement). On July 17, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on an interim basis pending a final hearing. Upon entry of a final order by the Bankruptcy Court, we will be granted the right to acquire all of the equity interests of the Ares JV owned by ECR in exchange for secured notes, cash and common stock upon emergence from bankruptcy. We have also agreed to certain covenants and amendments to the Ares JV limited liability company agreement. The Settlement Agreement may be terminated in certain limited circumstances. For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 6 Joint Ventures. Going Concern Analysis and Recent Developments 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 assets sales, joint ventures, debt exchanges, tenders and repurchases and other financing transactions to reduce our overall debt and improve our balance sheet. As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021. We currently expect that our cash flows, cash on hand and financing available through our DIP credit agreements should provide sufficient liquidity during the pendency of the Chapter 11 Cases. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 Cases is also subject to a high degree of uncertainty and is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court, our creditors, and Ares. There can be no assurance that we will confirm and consummate the plan under the RSA or complete another plan of reorganization with respect to the Chapter 11 proceedings. There is substantial doubt that we can continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases. For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 Cases. See Part II, Item 1A – Risk Factors , below for further discussion of these risks and risks related to our ability to continue as a going concern. 28 Operations Response to COVID-19 Pandemic and Industry Downturn We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity. In response to the rapid fall in commodity prices, we reduced our 2020 capital budget to a level that maintains the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner and ceased all field development and growth projects. As a result, our internally funded capital was $3 million in the second quarter of 2020. We also monetized all of our crude oil hedges for April 2020 forward with our counterparties, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to enhance our liquidity. We shut in certain wells to reduce operating costs which curtailed average gross production volumes by approximately 6 MBoe/d and average net production volumes by 5 MBoe/d during the second quarter of 2020. 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 current operating expense run rate is below $45 million per month compared to the first quarter average of $64 million per month. At our current level of capital investment, we anticipate production will continue to decline at a moderate pace through the remainder of the year. 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, including finance and accounting teams, 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, on April 6, 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. These reductions were made in an effort to preserve liquidity after the further deterioration of commodity prices following the outbreak of COVID-19. Our operational employees and contractors and certain support personnel have been classified as an essential critical infrastructure workforce by government authorities 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 private oil and natural gas mineral acreage holder in California, with interests in 2.2 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 renewable energy opportunities, agricultural activities and other commercial uses. 29 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 20% of our net production for the quarter ended June 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 costs but only our net share of production equally inflates our revenue and operating costs and has no effect on our net results. We own a large and geographically diverse portfolio of assets that generate the following revenue streams: Crude Oil — We sell nearly all of our crude oil into the California refining markets, which offer relatively favorable pricing for comparable grades relative to other U.S. regions. Substantially all of our crude oil production is connected, via our gathering systems, to third-party pipelines and California refining markets and we have not encountered any 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. 30 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 28% of our NGLs are sold to export markets. Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces operating costs and increases reliability. We sell the excess electricity generated to the grid and a local utility. The power sold to the utility is subject to agreements through the end of 2023, which include a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. The prices obtained for excess power impact our earnings but generally by an insignificant amount. Derivatives and Hedging Activities We opportunistically seek strategic hedging transactions to help protect our cash flow, operating margin and capital program from both the cyclical nature of commodity prices and interest rate movements while maintaining adequate liquidity and improving our ability to comply with our debt covenants. We can give no assurance that our hedging programs will be adequate to accomplish our objectives. In early March 2020, in response to the rapid fall in commodity prices, we monetized all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million to enhance our liquidity. As of June 30, 2020, we did not have any commodity hedges covering our share of production. The Senior DIP Credit Agreement requires 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 to satisfy this requirement. 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 June 30, 2020 by our development joint venture partners, before transaction costs: Cumulative Investment through June 30, 2020 (in millions) Alpine $ 231 Royale 17 MIRA 139 BSP 200 Total Capital Investment $ 587 31 For more information on our development joint ventures, please see our most recent Form 10-K for the year ended December 31, 2019. Alpine JV In July 2019, we entered into a development agreement with Alpine Energy Capital, LLC (Alpine). Alpine has committed to invest $320 million, which may be increased to a total investment of $500 million subject to the mutual agreement of the parties. The initial $320 million commitment covers multiple development opportunities and is intended to be invested over a period of up to three years in accordance with a 275-well development plan. On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below $45 per barrel over a 30-trading day period. The suspension is automatically lifted and Alpine is obligated to renew funding at such time as the average price exceeds that threshold over any 30-trading day period. If prices remain below the threshold for over 100 consecutive trading days, the development phase may be terminated by us, subject to agreement by Alpine. Ares JV In February 2018, our wholly owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream joint venture 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. We hold 50% of the Class A common interests and 95.25% of the Class C common interests in the Ares JV. ECR holds 50% of the Class A common interests, 100% of the Class B preferred interests and 4.75% of the Class C common interests. As contemplated by the terms of the joint venture, CREH purchases electricity, steam 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 will be 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 serves as the operator of the Ares JV and provides operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement. For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 6 Joint Ventures. For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 1 Basis of Presentation. Fixed and Variable Costs Our production costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. As a result of the measures taken to address the recent industry downturn, we continue to believe approximately one-third of our operating costs are fixed over the life cycle of our fields and the remaining two-thirds costs are variable. We actively manage our fields to optimize production and minimize costs. When we see growth in a field, we increase capacities and, similarly, when a field nears the end of its economic life, we manage the costs while it remains economically viable to produce. 32 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 six months ended June 30, 2020 and 2019: Three months ended June 30, Six months ended June 30, 2020 2019 2020 2019 Oil (MBbl/d) San Joaquin Basin 41 52 44 54 Los Angeles Basin 27 23 26 24 Ventura Basin 2 4 3 4 Total 70 79 73 82 NGLs (MBbl/d) San Joaquin Basin 13 15 14 14 Ventura Basin — 1 — 1 Total 13 16 14 15 Natural gas (MMcf/d) San Joaquin Basin 148 164 151 164 Los Angeles Basin 2 3 2 3 Ventura Basin 3 6 4 6 Sacramento Basin 21 30 22 29 Total 174 203 179 202 Total Net Production (MBoe/d) 112 129 117 131 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 June 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 17 MBoe/d or 13%. The decrease in production largely represented base decline resulting from low internal capital investment, 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. The shut in wells and the Lost Hills divestiture reduced our second quarter 2020 net production by 7 MBoe/d. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the second quarter of 2020 by over 5 MBoe/d compared to the same period in 2019. Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was below 12%, which is in line with our range of stated base decline rates. For the six months ended June 30,2020 compared to the same period in 2019, total daily production decreased by approximately 14 MBoe/d or 11%. The decrease in production largely represented base decline resulting from low internal capital investment, shut in production and the effect of the May 2019 partial divestiture of the Lost Hills field. The shut in wells and the Lost Hills divestiture reduced our net production for the six months ended June 30, 2020 by 7 MBoe/d. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the first half of 2020 by over 4 MBoe/d compared to the same period in 2019. Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was approximately 8%. 33 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 six months ended June 30, 2020 and 2019: Three months ended June 30, 2020 2019 Price Realization Price Realization Oil ($ per Bbl) Brent $ 33.27 $ 68.32 Realized price without hedge $ 30.27 91% $ 68.77 101% Settled hedges 0.55 1.89 Realized price with hedge $ 30.82 93% $ 70.66 103% WTI $ 27.85 $ 59.82 Realized price without hedge $ 30.27 109% $ 68.77 115% Realized price with hedge $ 30.82 111% $ 70.66 118% NGLs ($ per Bbl) Realized price (% of Brent) $ 21.05 63% $ 27.82 41% Realized price (% of WTI) $ 21.05 76% $ 27.82 47% Natural gas NYMEX ($/MMBtu) $ 1.77 $ 2.66 Realized price without hedge ($/Mcf) $ 1.65 93% $ 2.33 88% Settled hedges 0.08 0.03 Realized price with hedge ($/Mcf) $ 1.73 98% $ 2.36 89% Six months ended June 30, 2020 2020 2019 Price Realization Price Realization Oil ($ per Bbl) Brent $ 42.12 $ 66.11 Realized price without hedge $ 41.02 97% $ 65.97 100% Settled hedges 2.74 1.93 Realized price with hedge (a) $ 43.76 104% $ 67.90 103% WTI $ 37.01 $ 57.36 Realized price without hedge $ 41.02 111% $ 65.97 115% Realized price with hedge $ 43.76 118% $ 67.90 118% NGLs ($ per Bbl) Realized price (% of Brent) $ 25.18 60% $ 34.97 53% Realized price (% of WTI) $ 25.18 68% $ 34.97 61% Natural gas NYMEX ($/MMBtu) $ 1.91 $ 2.95 Realized price without hedge ($/Mcf) $ 1.96 103% $ 2.87 97% Settled hedges 0.09 (0.01) Realized price with hedge ($/Mcf) $ 2.05 107% $ 2.86 97% (a) Prices for the first six months of 2020 exclude the effect of $63 million of proceeds received in the first quarter of 2020 from settling derivative contracts with counterparties prior to maturity. 34 Oil — Brent index and realized prices were lower in both the three and six months ended June 30, 2020 compared to the same prior-year period due to the combination of the supply increase caused by the Saudi-Russia price war and the severe demand decline caused by COVID-19. Further, our realizations without hedge were significantly affected in the three months ended June 30, 2020, and to a lesser extent in the six months ended June 30, 2020, primarily due to the unprecedented global oversupply of oil and Saudi Arabia's price cuts for oil to the U.S. and other markets in April 2020. These two events led to lower crude realizations for foreign oil imported into California and depressed prices for native California crude. NGLs — Prices for NGLs decreased from the same prior-year period as supply associated with high gas-producing basins outpaced steady demand, causing lower domestic NGL prices in the three and six months ended June 30, 2020. We continue 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 six months ended June 30, 2020 than the comparable periods of 2019. The decrease was due to increased nationwide natural gas production and 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. Balance Sheet Analysis The following table sets forth changes in our balance sheet between June 30, 2020 and December 31, 2019: June 30, December 31, 2020 2019 (in millions) Cash $ 126 $ 17 Trade receivables $ 132 $ 277 Inventories $ 61 $ 67 Other current assets, net $ 84 $ 130 Property, plant and equipment, net $ 4,449 $ 6,352 Other assets $ 78 $ 115 Current portion of long-term debt $ 5,083 $ 100 Current deferred gain and issuance costs, net $ 125 $ — Accounts payable $ 196 $ 296 Accrued liabilities $ 355 $ 313 Long-term debt $ — $ 4,877 Deferred gain and issuance costs, net $ — $ 146 Other long-term liabilities $ 719 $ 720 Mezzanine equity $ 828 $ 802 Equity attributable to common stock $ (2,452) $ (389) Equity attributable to noncontrolling interests $ 76 $ 93 Cash — Cash at June 30, 2020 and December 31, 2019 included restricted cash of $21 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 June 2020 compared to December 2019. Other current assets, net — The decrease in other current assets, net was primarily due to the sale of our crude oil hedge positions resulting in a decrease in the fair value of the current portion of our derivative assets. Additionally, in March 2020, we recorded an $11 million impairment on capital investments to be recovered from our joint interest partners solely from production. 35 Property, plant and equipment, net — The decrease in property, plant and equipment, net primarily reflected the $1.7 billion impairment of certain of our proved and unproved properties recorded in the first quarter of 2020, depreciation, depletion, and amortization (DD&A) and to a lesser extent sales of certain royalty interests and non-core assets in the first quarter of 2020. The decrease was partially offset by capital investments including the planned major maintenance at our Elk Hills power plant. For further detail about the asset impairment, see Part I, Item 1 – Financial Statements, Note 14 Asset Impairments . Other assets — Other assets decreased primarily due to utilizing parts for the planned major maintenance of our Elk Hills power plant as well as a decrease in operating lease assets due to releasing drilling rigs in the first quarter of 2020. Current portion of long-term debt — The increase in the current portion of long-term debt was a result of the reclassification of our long-term debt to current as described in Part I, Item 1 – Financial Statements, Note 5 Debt . Current portion of deferred gain and issuance costs, net — The increase in the current portion of deferred gain and issuance costs, net was primarily a result of reclassifying capitalized costs associated with our long-term debt to current. Accounts payable — The decrease in accounts payable was due to lower amounts payable to vendors following the reduction of our capital plan in the second quarter of 2020 compared to the fourth quarter of 2019. Accrued liabilities — The increase in accrued liabilities primarily related to an increase in accrued interest as a result of our failure to make certain interest payments and property tax payments during the second quarter of 2020 compared to balances due as of the fourth quarter of 2019. These amounts were partially offset by the bonus payments to employees made in the first quarter of 2020 with respect to 2019 performance as well as a decrease in activities of the Alpine JV following their suspension of further capital funding due to low commodity prices. Long-term debt — The decrease in long-term debt resulted from the reclassification of long-term debt to current as of June 30, 2020. Deferred gain and issuance costs, net — The decrease in deferred gain and issuance costs, net resulted from the reclassification of costs associated with our long-term debt to current as of June 30, 2020. Mezzanine equity — The increase in mezzanine equity primarily resulted from the preferred return to the Class B interests held by the noncontrolling interest partner in our Ares JV. Equity attributable to common stock — Equity attributable to common stock decreased primarily as a result of the net loss in the six months ended June 30, 2020. Statements of Operations Analysis Results of Oil and Gas Operations The following represents key operating data for our oil and gas operations, excluding certain corporate items, on a per Boe basis for the three and six months ended June 30, 2020 and 2019: Three months ended June 30, Six months ended June 30, 2020 2019 2020 2019 Production costs $ 12.42 $ 19.62 $ 14.99 $ 19.54 Production costs, excluding effects of PSC-type contracts (a) $ 12.00 $ 17.98 $ 14.33 $ 17.99 Field general and administrative expenses (b) $ 1.17 $ 1.28 $ 1.08 $ 1.27 Field depreciation, depletion and amortization (b) $ 7.82 $ 9.55 $ 8.98 $ 9.47 Field taxes other than on income (b) $ 2.84 $ 2.39 $ 2.96 $ 2.53 (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. 36 Consolidated Results of Operations The following represents key operating data for our consolidated operations for the three and six months ended June 30, 2020 and 2019: Three months ended June 30, Six months ended June 30, 2020 2019 2020 2019 (in millions) Oil and natural gas sales $ 245 $ 578 $ 675 $ 1,179 Net derivative (loss) gain from commodity contracts (4) 21 75 (68) Other revenue 35 54 99 232 Production costs (127) (230) (319) (463) General and administrative expenses (69) (79) (129) (162) Depreciation, depletion and amortization (88) (121) (207) (239) Asset impairments — — (1,736) — Taxes other than on income (38) (36) (79) (77) Exploration expense (2) (10) (7) (20) Other expenses, net (67) (55) (136) (203) Interest and debt expense, net (85) (98) (172) (198) Net gain on early extinguishment of debt — 20 5 26 Other non-operating expenses (47) (3) (61) (10) (Loss) income before income taxes (247) 41 (1,992) (3) Income tax — — — — Net (loss) income (247) 41 (1,992) (3) Net income attributable to noncontrolling interests (24) (29) (75) (52) Net (loss) income attributable to common stock $ (271) $ 12 $ (2,067) $ (55) Adjusted net (loss) income (a) $ (202) $ (14) $ (210) $ 17 Adjusted EBITDAX (a) $ 19 $ 255 $ 270 $ 556 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. Three months ended June 30, 2020 vs. 2019 Oil and natural gas sales — Oil and natural gas sales decreased 58%, or $333 million, for the three months ended June 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 June 30, 2019 $ 496 $ 39 $ 43 $ 578 Changes in realized prices (279) (10) (13) (302) Changes in production (24) (3) (4) (31) Three months ended June 30, 2020 $ 193 $ 26 $ 26 $ 245 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 $5 million for the three months ended June 30, 2020 compared to net proceeds of $14 million for the same period of 2019, which had a negative impact of $9 million on our total revenue between periods. Including the effect of settled hedges, our oil and natural gas revenue decreased by $342 million or 58% compared to the same prior-year period. 37 Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $4 million for the three months ended June 30, 2020 compared to a gain of $21 million in the same period of 2019, representing an overall change of $25 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. Three months ended June 30, 2020 2019 (in millions) Non-cash derivative (loss) gain, excluding noncontrolling interest $ — $ 4 Non-cash derivative (loss) gain, noncontrolling interest (9) 3 Total non-cash changes (9) 7 Net proceeds on settled commodity derivatives 5 14 Net derivative (loss) gain $ (4) $ 21 Other revenue — The decrease in other revenue of $19 million to $35 million for the three months ended June 30, 2020 compared to $54 million in the same period of 2019 was primarily due to lower natural gas trading activity. Production costs — Production costs for the three months ended June 30, 2020 decreased $103 million to $127 million compared to $230 million for the same period of 2019, resulting in a 45% decrease. The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our October 2019 workforce reduction 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. General and administrative expenses — Our general and administrative (G&A) expenses decreased $10 million to $69 million for the three months ended June 30, 2020 compared to $79 million for the same period of 2019, primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods. Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 workforce reduction and reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic in the second quarter of 2020 partially offset by additional compensation expense related to the modification of our 2020 variable compensation programs in May 2020. See Part I, Item 1 – Financial Statements, Note 15 Compensation Plans for more information. Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $33 million to $88 million in the second quarter of 2020 compared to $121 million 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. Other expenses, net — The increase in other expenses of $12 million to $67 million for the three months ended June 30, 2020 compared to $55 million for the same period of 2019 was largely the result of a one-time payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract partially offset by a decrease in natural gas trading purchases. Interest and debt expense, net — Interest and debt expense, net decreased $13 million to $85 million in the second quarter of 2020 compared to $98 million in the same period of 2019 due to the repayment of the 2020 Senior Notes in January 2020, the 2019 repurchases of our Second Lien Notes and lower variable interest rates on our borrowings under the 2016 Credit Agreement and 2017 Credit Agreement. Net gain on early extinguishment of debt — We did not have a net gain on early extinguishment of debt for the three months ended June 30, 2020, which is a decrease of $20 million from the same period in 2019. The decrease was due to a lack of open market purchases in the second quarter of 2020. Other non-operating expense — Other non-operating expense increased $44 million to $47 million for the three months ended June 30, 2020 compared to $3 million in the same period for 2019. The increase was primarily a result of professional fees and costs associated with the preparation of the Chapter 11 Cases. 38 Six months ended June 30, 2020 vs 2019 Oil and natural gas sales — Oil and natural gas sales decreased 43%, or $504 million, for the six months ended June 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) Six months ended June 30, 2019 $ 976 $ 98 $ 105 $ 1,179 Changes in realized prices (371) (27) (33) (431) Changes in production (56) (9) (8) (73) Six months ended June 30, 2020 $ 549 $ 62 $ 64 $ 675 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 $40 million for the six months ended June 30, 2020, excluding the effect of our derivative contracts sold prior to maturity in the first quarter of 2020, compared to net proceeds of $28 million for the same period of 2019, which had a positive impact of $12 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 $429 million or 36% compared to the same prior-year period. Net derivative gain (loss) from commodity contracts — Net derivative gain from commodity contracts was $75 million for the six months ended June 30, 2020 compared to a loss of $68 million in the same period of 2019, representing an overall change of $143 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. Six months ended June 30, 2020 2019 (in millions) Non-cash derivative (loss) gain, excluding noncontrolling interest $ (35) $ (93) Non-cash derivative gain (loss), noncontrolling interest 7 (3) Total non-cash changes (28) (96) Net proceeds on settled commodity derivatives 40 28 Net proceeds on derivative sales prior to maturity 63 — Net derivative gain (loss) $ 75 $ (68) Other revenue — The decrease in other revenue of $133 million to $99 million for the six months ended June 30, 2020 compared to $232 million in the same period of 2019 was due to lower natural gas trading activity and lower electricity sales due to a planned major maintenance at the Elk Hills power plant in 2020. Production costs — Production costs for the six months ended June 30, 2020 decreased $144 million to $319 million compared to $463 million for the same period of 2019, resulting in a 31% decrease. The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our October 2019 workforce reduction 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. General and administrative expenses — Our general and administrative (G&A) expenses decreased $33 million to $129 million for the six months ended June 30, 2020 compared to $162 million for the same period of 2019, primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods. Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 workforce reduction and reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic in the second quarter of 2020 partially offset by an increase in compensation expense due to changes to our 2020 compensation program. 39 Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $32 million to $207 million in the first half of 2020 compared to $239 million in 2019 was predominately due to the 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 $228 million related to unproved acreage that we no longer intend to pursue. No asset impairments were recorded in the second quarter of 2020. For further detail about the asset impairment, see Part I, Item 1 – Financial Statements, Note 14 Asset Impairments . Other expenses, net — The decrease in other expenses of $67 million to $136 million for the six months ended June 30, 2020 compared to $203 million for the same period of 2019 was largely the result of lower natural gas trading activity, partially offset by a one-time deficiency payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract. Interest and debt expense, net — Interest and debt expense, net decreased $26 million to $172 million in the first half of 2020 compared to $198 million in the same period of 2019 due to the repayment of the 2020 Senior Notes in January 2020, reduction in the outstanding balance of the Second Lien Notes due to open market purchases and a reduction in the interest rates in our 2016 Credit Agreement and 2017 Credit Agreement. Net gain on early extinguishment of debt — The net gain on early extinguishment of debt for the six months ended June 30, 2020 was $5 million, which is a decrease of $21 million from $26 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 $51 million to $61 million for the six months ended June 30, 2020 compared to $10 million in the same period for 2019. The increase was primarily a result of professional fees and costs associated with the preparation of the Chapter 11 Cases. Stock-Based Compensation Our consolidated results of operations for the three and six months ended June 30, 2020 and 2019 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include stock options, restricted stock units and performance stock units that either cliff vest at the end of a three-year period or vest ratably over a three-year period, some of which are partially settled in cash. Our equity-settled awards granted to non-employee directors are stock grants that vest immediately or restricted stock units that cliff vest after one year. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period. Changes in our stock price introduce volatility in our results of operations because we pay cash-settled awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Cash-settled awards, including executive awards partially settled in cash, account for approximately 40% of our total outstanding awards. Our obligations for equity-settled awards are not similarly adjusted for changes in our stock price. 40 Stock-based compensation is included in both general and administrative (G&A) expense and production costs as shown in the table below: Three months ended June 30, Six months ended June 30, 2020 2019 Variance 2020 2019 Variance (in millions, except per Boe amounts) G&A expense Cash-settled awards $ — $ 3 $ (3) $ (2) $ 13 $ (15) Equity-settled awards 1 4 (3) 4 7 (3) Total in G&A $ 1 $ 7 $ (6) $ 2 $ 20 $ (18) Total in G&A per Boe $ 0.10 $ 0.60 $ (0.50) $ 0.10 $ 0.84 $ (0.74) Production costs Cash-settled awards $ — $ 1 $ (1) $ (1) $ 4 $ (5) Equity-settled awards — 1 (1) — 2 (2) Total in production costs $ — $ 2 $ (2) $ (1) $ 6 $ (7) Total in production costs per Boe $ — $ 0.17 $ (0.17) $ (0.05) $ 0.25 $ (0.30) Total stock-based compensation expense $ 1 $ 9 $ (8) $ 1 $ 26 $ (25) Total stock-based compensation expense per Boe $ 0.10 $ 0.77 $ (0.67) $ 0.05 $ 1.09 $ (1.04) Changes to the 2020 Compensation Program In connection with the unprecedented circumstances affecting the industry and market volatility resulting from the recent industry downturn, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately align compensation opportunities with our 2020 goals and ensure the stability of our workforce. Following this review, effective May 19, 2020, our 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 will be settled in cash and the replacement awards are no longer stock-based compensation. 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. There were no changes to stock-based compensation awards granted prior to February 2020. Changes to the variable compensation programs will have 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 remains largely the same as the amounts that would have been paid at target prior to the changes. Our second quarter 2020 results included an additional $4 million expense related to modifying our 2020 compensation program. See Non-GAAP Financial Measures below for a reconciliation of G&A to adjusted G&A. Non-GAAP Financial Measures Adjusted net (loss) income — Our results of operations, which are presented in accordance with U.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses 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. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. 41 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 June 30, Six months ended June 30, 2020 2019 2020 2019 (in millions, except share data) Net (loss) income $ (247) $ 41 $ (1,992) $ (3) Net income attributable to noncontrolling interests (24) (29) (75) (52) Net (loss) income attributable to common stock (271) 12 (2,067) (55) Unusual, infrequent and other items: Asset impairment — — 1,736 — Non-cash derivative (loss) gain from commodities, excluding noncontrolling interest — (4) 35 93 Severance costs — 2 — 2 Incentive and retention award modification 4 — 4 — Net gain on early extinguishment of debt — (20) (5) (26) Professional fees and costs related to our Chapter 11 Cases 42 — 49 — Deficiency payment on a pipeline delivery contract 20 — 20 — Other, net 3 (4) 18 3 Total unusual, infrequent and other items 69 (26) 1,857 72 Adjusted net (loss) income $ (202) $ (14) $ (210) $ 17 Net (loss) income attributable to common stock per diluted share $ (5.47) $ 0.24 $ (41.84) $ (1.13) Adjusted net (loss) income per diluted share $ (4.08) $ (0.29) $ (4.25) $ 0.35 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. A version of adjusted EBITDAX is a material component of certain of our financial covenants under our 2014 Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted EBITDAX: Three months ended June 30, Six months ended June 30, 2020 2019 2020 2019 (in millions) Net (loss) income $ (247) $ 41 $ (1,992) $ (3) Interest and debt expense, net 85 98 172 198 Depreciation, depletion and amortization 88 121 207 239 Exploration expense 2 10 7 20 Unusual, infrequent and other items 69 (26) 1,857 72 Other non-cash items 22 11 19 30 Adjusted EBITDAX $ 19 $ 255 $ 270 $ 556 42 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: Six months ended June 30, 2020 2019 (in millions) Net cash provided by operating activities $ 93 $ 272 Cash interest 59 225 Exploration expenditures 7 10 Working capital changes 111 49 Adjusted EBITDAX $ 270 $ 556 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 consolidated general and administrative expenses to the non-GAAP measure of adjusted G&A: Three months ended June 30, Six months ended June 30, 2020 2019 2020 2019 (in millions) (in millions) General and administrative expenses $ 69 $ 79 $ 129 $ 162 Incentive and retention award modification (4) — (4) — Severance costs — (1) — (1) Office consolidation — (1) — (1) Adjusted G&A $ 65 $ 77 $ 125 $ 160 Liquidity and Capital Resources Cash Flow Analysis Six months ended June 30, 2020 2019 (in millions) Cash flow from operating activities $ 93 $ 272 Cash flow from investing activities: Capital investments $ (33) $ (271) Changes in capital investment accruals $ (28) $ (57) Acquisitions, divestitures and other $ 34 $ 158 Cash flow from financing activities: Net debt transactions $ 110 $ (74) Net distributions to noncontrolling interest holders $ (66) $ (16) Issuance of common stock and other $ (1) $ (2) 43 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 66%, or $179 million, to $93 million for the six months ended June 30, 2020 from $272 million in the same period of 2019. Changes in operating assets and liabilities, net in the six months ended June 30, 2020 increased our operating cash flow by $130 million compared to a reduction of $52 million in the comparable six months of 2019. This positive change primarily resulted from a decrease in accounts receivable due to lower commodity prices between periods partially offset by lower trade payables as a result of our reduced capital plan and cost saving initiatives. Operating cash flow in the first six months of 2020 also reflected the positive contribution of the $63 million of proceeds from the early settlement of derivative contracts. Cash flows from investing activities — Our net cash used in investing activities of $27 million for the six months ended June 30, 2020 primarily reflected $33 million of capital investments (excluding $28 million 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 first half of 2020. For the six months ended June 30, 2019, our net cash used in investing activities of $170 million primarily included approximately $271 million of capital investments (excluding $57 million in capital-related accrual changes), of which $43 million was funded by BSP, partially offset by $165 million of proceeds related to our Lost Hills sale. Cash flows from financing activities — Our net cash provided by financing activities of $43 million for the six months ended June 30, 2020 primarily included $213 million in net proceeds on our 2014 Revolving Credit Facility partially offset by $100 million for the repayment of the 2020 Senior Notes at maturity, $68 million of distributions to our noncontrolling interest holders and $3 million for debt repurchases of our Second Lien Notes. We also had an additional $2 million in contributions from a noncontrolling interest holder. For the six months ended June 30, 2019, our net cash used in financing activities of $92 million was primarily comprised of $59 million used for debt repurchases of our Senior Notes, $65 million of distributions paid to our non-controlling interest holders, and $15 million of net repayments on our 2014 Revolving Credit Facility partially offset by $49 million in a net contribution from a noncontrolling interest holder. Liquidity Our spin–off from 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 assets sales, joint ventures, debt exchanges, tenders and repurchases and other financing transactions to reduce our overall debt and improve our balance sheet. As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021. The commencement of the Chapter 11 Cases constituted an immediate event of default that automatically accelerated our obligations under the 2014 Revolving Credit Facility and our other debt agreements. Any efforts to enforce payment obligations related to the acceleration of our obligations under these 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 June 30, 2020, we had available cash of $105 million and no ability to borrow under our 2014 Revolving Credit Facility due to the missed interest payments and forbearance described below. As of June 30, 2020 and December 31, 2019, we had letters of credit outstanding of $152 million and $165 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters. For more information on our debt, see Part I, Item 1 – Financial Statements, Note 5 Debt and for more information on the Chapter 11 Cases, see Part I, Item 1 – Financial Statements, Note 1 Basis of Presentation. 44 Debtor-in-Possession Credit Agreements On July 23, 2020, we entered into the Senior DIP Credit Agreement which provides for a Senior DIP Facility in an aggregate principal amount of up to approximately $483 million. The Senior DIP Facility includes a $250 million revolving facility which will be primarily used by us to (i) fund working capital needs and capital expenditures and additional letters of credit during the pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Senior DIP Facility. Until the Bankruptcy Court enters a final order with respect to our DIP credit agreements, only $85 million of revolving borrowings are available. If the Bankruptcy Court enters a final order approving the Senior DIP Facility in its current form following a hearing on August 14, 2020, we expect the full remaining amount of the $250 million revolving facility to become available. The Senior DIP Facility also includes (a) a $150 million letter of credit facility which was used to deem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (b) $83 million of term loans borrowings which were used to repay a portion of the 2014 Revolving Credit Facility. On July 23, 2020, we also entered into a Junior DIP Credit Agreement which provides for a Junior DIP Facility in an aggregate principal amount of $650 million. The proceeds of the Junior DIP Facility were used to (i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility. The Senior DIP Credit Agreement and Junior DIP Credit Agreement include conditions precedent, representations and warranties, affirmative and negative covenants and events of default customary for financings of their type and size. The Senior DIP Facility and the Junior DIP Facility both mature on January 15, 2021. See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our DIP credit agreements. Missed Interest Payments and Forbearance On May 15, 2020, we did not make an interest payment of approximately $4 million on our 2024 Notes. The indenture governing our 2024 Notes provides for a 30-day grace period and the payment was subsequently made on June 12, 2020. On May 29, 2020, we did not pay approximately $51 million in the aggregate interest due under the 2017 Credit Agreement and the 2016 Credit Agreement. Our failure to make those interest payments constituted events of default under the 2017 Credit Agreement, 2016 Credit Agreement and, as a result of cross default, under the 2014 Revolving Credit Facility. On June 2, 2020, we entered into Forbearance Agreements with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement. Pursuant to the Forbearance Agreements, the lenders who are parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, initially through June 14, 2020 and subsequently through July 15, 2020. On June 15, 2020, we did not make an interest payment of approximately $72 million on our Second Lien Notes. The indenture governing the Second Lien Notes provides for a 30-day grace period, which expired on July 15, 2020. 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. 45 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 approximately $63 million to enhance our liquidity. As of June 30, 2020, we did not have any commodity hedges covering our share of production. The Senior DIP Credit Agreement requires 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 to satisfy this requirement. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges. We currently have the following Brent-based crude oil contracts: August-September 2020 Q4 2020 Q1 2021 Q2 2021 July 2021 Sold Calls: Barrels per day 4,950 4,800 4,500 4,500 4,200 Weighted-average price per barrel $ 48.05 $ 48.05 $ 48.05 $ 48.05 $ 48.05 Purchased Puts: Barrels per day 9,900 9,600 9,000 9,000 8,400 Weighted-average price per barrel $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 Sold Puts: Barrels per day 4,950 4,800 4,500 4,500 4,200 Weighted-average price per barrel $ 30.00 $ 30.00 $ 30.00 $ 30.00 $ 30.00 Swaps: Barrels per day 6,600 6,400 6,000 6,000 5,600 Weighted-average price per barrel $ 44.75 $ 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. 46 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 $33 million of internally funded capital investments in the first half of 2020 and expect to invest up to an additional $20 million through the end of 2020. In order to meet this level of investment, we suspended all internally funded drilling and capital workovers for the second quarter and significantly reduced other activities. Our JV partners invested $98 million in the first half 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 six months ended June 30, 2020 and 2019: Six months ended June 30, 2020 2019 (in millions) Oil and natural gas $ 32 $ 212 Exploration — 9 Corporate and other 1 7 Total internally funded capital 33 228 BSP funded capital — 43 Total consolidated capital investment $ 33 $ 271 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. 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. 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 June 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 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, governmental authorities may determine to continue actions brought under regulatory powers. 47 Significant Accounting and Disclosure Changes See Part I, Item 1, Note 2 Accounting and Disclosure Changes in the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for a discussion of new accounting matters. 48 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, including our ability to operate as a going concern • 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 • ability to pay our creditors • ability to comply with the covenants in our debt agreements and instruments • credit ratings 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: • risks and uncertainties relating to the Chapter 11 Cases filed in the Bankruptcy Court, including our ability to obtain the Bankruptcy Court’s approval with respect to our motions, our ability to develop, confirm and consummate a Chapter 11 plan or an alternative restructuring transaction, risks associated with third-party motions, Bankruptcy Court rulings and the outcome of the Chapter 11 Cases in general, and the length of time we will operate under the Chapter 11 Cases • the potential adverse effects of disruption from the Chapter 11 Cases on us, our liquidity and/or results of operations, and on the interests of our various constituents making it more difficult to maintain business and operational relationships, retain key executives and maintain various licenses and approvals necessary for us to conduct our business • our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence; • risk and uncertainties relating to our ability to obtain requisite support for our Chapter 11 plan from various stakeholders and confirm and consummate that plan • increased advisory costs to execute a reorganization • risks associated with our ability to continue as a going concern • the impact of the NYSE’s delisting of our common stock on the liquidity and market price of our common stock and on our ability to access the public capital markets; • risks related to the trading of our securities on the OTC Pink Market • the volatility of and potential for sustained low oil, natural gas and NGL prices • commodity price changes, including extended periods of low oil, natural gas or NGL prices • debt limitations on our financial flexibility • inability to reach an agreement with our creditors with respect to a restructuring of our debt • 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 49 • 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 • 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 COVID-19 pandemic • factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K available at www.crc.com. Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 50