California Resources Corp 10-Q

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations General We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries. We are committed to energy transition in the energy sector and have some of the lowest carbon intensity production in the United States. Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several carbon capture and sequestration projects in the San Joaquin Valley. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant. We are also pursuing multiple front-of-the-meter and behind-the-meter solar projects. We qualified for and adopted fresh start accounting upon emergence from bankruptcy on October 27, 2020, at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of our joint plan of reorganization (the Plan), the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting. Business Environment and Industry Outlook Commodity Prices Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Global oil prices were higher in the three and nine months ended September 30, 2021 compared to the same periods in 2020. Benchmark prices for Brent crude oil in the first nine months of 2021 increased 59% from the same period in 2020 as a result of steady draws on global inventories demonstrating a strong recovery from the same prior year period when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) pandemic and by the actions of foreign producers. 24 The following table presents the average daily Brent, WTI and NYMEX prices for the three and nine months ended September 30, 2021 and 2020: Three months ended September 30, Nine months ended September 30, 2021 2020 2021 2020 Brent oil ($/Bbl) $ 73.23 $ 43.37 $ 67.78 $ 42.53 WTI oil ($/Bbl) $ 70.56 $ 40.93 $ 64.82 $ 38.32 NYMEX gas ($/MMBtu) $ 3.71 $ 1.93 $ 3.06 $ 1.92 Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production and Prices and Part II, Item 1A – Risk Factors in our 2020 Annual Report for further discussion regarding the impact of the pandemic and declines in commodity prices. Production The following table sets forth our average net production of oil, natural gas liquids (NGLs) and natural gas per day in each of the four California oil and natural gas basins in which we operate for the periods presented. See Part I, Item 1 – Financial Statements, Note 6 Assets Held for Sale and Note 16 Subsequent Events for information regarding the divestiture of our Ventura basin operations. Successor Predecessor Successor Predecessor Three months ended September 30, Three months ended September 30, Nine months ended September 30, Nine months ended September 30, 2021 2020 2021 2020 Oil (MBbl/d) San Joaquin Basin 40 40 39 42 Los Angeles Basin 19 22 19 25 Ventura Basin 3 2 3 3 Total 62 64 61 70 NGLs (MBbl/d) San Joaquin Basin 13 14 13 14 Total 13 14 13 14 Natural gas (MMcf/d) San Joaquin Basin 135 142 135 148 Los Angeles Basin 1 2 1 2 Ventura Basin 5 4 5 4 Sacramento Basin 19 20 19 21 Total 160 168 160 175 Total Net Production (MBoe/d) 102 106 101 113 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. Total daily production for the three months ended September 30, 2021, compared to the same period in 2020, decreased by approximately 4 MBoe/d or 4%. For the nine months ended September 30, 2021 compared to the same period in 2020, total daily production decreased by approximately 12 MBoe/d or 11%. The decrease in production largely resulted from limited drilling activity and capital investment during 2020 and natural decline rates. This decrease was partially offset by improved operational results from our 2021 drilling program and our acquisition of the working interests in certain joint venture wells held by Macquarie Infrastructure and Real Assets Inc. (MIRA) in the third quarter of 2021. Our production-sharing contracts (PSCs), which are described below, negatively impacted our oil production in the three and nine months ended September 30, 2021 by approximately 1 MBoe/d and approximately 3 MBoe/d, respectively, compared to the same periods in 2020. 25 Production-Sharing Contracts (PSCs) Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 15% of our net production for the three months ended September 30, 2021. In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs. 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 oil, natural gas and NGL sales revenue, general and administrative expenses and operating costs but has no effect on our net results. The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for excess costs attributable to PSC-type contracts for the three and nine months ended September 30, 2021: Three months ended September 30, 2021 Nine months ended September 30, 2021 (in millions) ($ per Boe) (in millions) ($ per Boe) Operating costs $ 190 $ 20.28 $ 523 $ 19.04 Excess costs attributable to PSC-type contracts (17) $ (1.84) (47) $ (1.72) Operating costs, excluding effects of PSC-type contracts (a) $ 173 $ 18.44 $ 476 $ 17.32 (a) Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure. As described above, the reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. These amounts represent our operating costs after adjusting for this difference. 26 Prices and Realizations 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, 2021 and 2020: Successor Predecessor Three months ended September 30, Three months ended September 30, 2021 2020 Price Realization Price Realization Oil ($ per Bbl) Brent $ 73.23 $ 43.37 Realized price without derivative settlements $ 72.89 100% $ 41.83 96% Effects of derivative settlements (17.47) 0.32 Realized price with derivative settlements $ 55.42 76% $ 42.15 97% WTI $ 70.56 $ 40.93 Realized price without derivative settlements $ 72.89 103% $ 41.83 102% Realized price with derivative settlements $ 55.42 79% $ 42.15 103% NGLs ($ per Bbl) Realized price (% of Brent) $ 53.74 73% $ 25.16 58% Realized price (% of WTI) $ 53.74 76% $ 25.16 61% Natural gas NYMEX ($/MMBtu) $ 3.71 $ 1.93 Realized price without derivative settlements ($/Mcf) $ 4.66 126% $ 2.22 115% Effects of derivative settlements (0.02) 0.02 Realized price with derivative settlements ($/Mcf) $ 4.64 125% $ 2.24 116% 27 Successor Predecessor Nine months ended September 30, Nine months ended September 30, 2021 2020 Price Realization Price Realization Oil ($ per Bbl) Brent $ 67.78 $ 42.53 Realized price without derivative settlements $ 67.62 100% $ 41.27 97% Effects of derivative settlements (13.19) 2.00 Realized price with derivative settlements $ 54.43 80% $ 43.27 102% WTI $ 64.82 $ 38.32 Realized price without derivative settlements $ 67.62 104% $ 41.27 108% Realized price with derivative settlements $ 54.43 84% $ 43.27 113% NGLs ($ per Bbl) Realized price (% of Brent) $ 49.20 73% $ 25.17 59% Realized price (% of WTI) $ 49.20 76% $ 25.17 66% Natural gas NYMEX ($/MMBtu) $ 3.06 $ 1.92 Realized price without derivative settlements ($/Mcf) $ 3.67 120% $ 2.05 107% Effects of derivative settlements (0.03) 0.06 Realized price with derivative settlements ($/Mcf) $ 3.64 119% $ 2.11 110% Oil — Brent index and realized prices excluding hedge settlements were higher in the three and nine month periods ended September 30, 2021 compared to the same periods in 2020 as oil demand has been bolstered by the re-opening of economies and easing of mobility restrictions related to the COVID-19 pandemic. Prices have also increased due to a rise in domestic demand and lower supply caused by reduced investment in the U.S. upstream oil and gas sector during 2020 as well as supply management by OPEC members. NGLs — Prices for NGLs increased for the three and nine month periods ended September 30, 2021 compared to the same periods in 2020. Higher prices are the result of increased demand in the U.S. and abroad. Natural Gas — For the three and nine months ended September 30, 2021, natural gas prices have increased compared to the same prior year periods. Increases in pricing – both across the United States and within California – have been driven by strong industrial and export demand. 28 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, 2021 and 2020. Energy operating costs consist of purchases of natural gas used to generate electricity, purchased electricity and internal costs to generate electricity used in our operations. Non-energy operating costs equal total operating costs less energy costs and gas processing costs. However, non-energy operating costs include the costs of purchasing natural gas used to generate steam for our steamfloods. Successor Predecessor Successor Predecessor Three months ended September 30, Three months ended September 30, Nine months ended September 30, Nine months ended September 30, 2021 2020 2021 2020 Energy operating costs $ 5.49 $ 4.25 $ 4.97 $ 3.81 Gas processing costs $ 0.56 $ 0.46 $ 0.59 $ 0.54 Non-energy operating costs $ 14.23 $ 9.81 $ 13.48 $ 10.50 Operating costs (a) $ 20.28 $ 14.52 $ 19.04 $ 14.85 Field general and administrative expenses (b) $ 0.96 $ 1.34 $ 0.87 $ 1.16 Field depreciation, depletion and amortization (c) $ 5.12 $ 8.03 $ 5.21 $ 8.68 Field taxes other than on income (d) $ 2.67 $ 3.40 $ 3.02 $ 3.10 (a) Operating costs increased in the three and nine months ended September 30, 2021 from the same prior year period primarily as a result of higher downhole maintenance activity in 2021 as well as increased energy costs and natural gas prices as compared to 2020. These increases were partially offset by lower compensation-related costs from headcount reductions and reduced employee benefit costs. The prior year comparative periods include cost savings from measures we took in 2020 to streamline our operations and in the months of April and May 2020 we reduced work hours due to the dramatic decrease in commodity prices. For the non-GAAP measure of operating costs, excluding the effects of PSC-type contracts, see Production, Production-Sharing Contracts above. (b) Excludes corporate general and administrative expenses. Field general and administrative expenses decreased for the three and nine months ended September 30, 2021 from the same period in 2020 primarily due to workforce reductions in the second half of 2020 and the first quarter of 2021. (c) Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant. Field depreciation, depletion and amortization decreased in the three and nine months ended September 30, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the fresh start valuation of our property, plant and equipment. (d) Field taxes other than on income decreased in the three months ended September 30, 2021 compared to the same prior year period primarily due to lower ad valorem taxes which are sensitive to commodity prices and generally determined at the beginning of each calendar year. Commodity prices were lower in early 2021 as compared to early 2020. 29 Consolidated Results of Operations Three months ended September 30, 2021 vs. 2020 The following table presents our operating revenues for the three months ended September 30, 2021 and 2020: Successor Predecessor Three months ended September 30, Three months ended September 30, 2021 2020 (in millions) Oil, natural gas and NGL sales $ 549 $ 312 Net (loss) gain from commodity derivatives (125) — Sales of purchased natural gas 95 50 Electricity sales 65 43 Other revenue 4 4 Total operating revenues $ 588 $ 409 Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of derivative settlements, were $549 million for the three months ended September 30, 2021, which is an increase of $237 million compared to $312 million for the same period of 2020. The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table: Oil NGLs Natural Gas Total (in millions) Three months ended September 30, 2020 $ 246 $ 32 $ 34 $ 312 Changes in realized prices 182 36 38 256 Changes in production (15) (1) (3) (19) Three months ended September 30, 2021 $ 413 $ 67 $ 69 $ 549 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. The effect of settlements on our commodity derivatives is not included in the table above. Payments for derivative settlements were $99 million for the three months ended September 30, 2021 compared to proceeds of $2 million for the same period of 2020. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $136 million or 43% compared to the same prior-year period. Net loss from commodity derivatives — Net loss from commodity derivatives was $125 million for the three months ended September 30, 2021 as shown in the table below. We did not have significant commodity derivatives during the same period of 2020. The non-cash changes in the fair value of our outstanding commodity derivatives resulted from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward curves. Three months ended September 30, Three months ended September 30, 2021 2020 (in millions) Non-cash commodity derivative (loss) gain, excluding noncontrolling interest $ (26) $ 4 Non-cash commodity derivative loss, noncontrolling interest — (6) Total non-cash changes (26) (2) Net (payments) proceeds on settled commodity derivatives (99) 2 Net loss from commodity derivatives $ (125) $ — 30 Sales of purchased natural gas — Sales of purchased natural gas was $95 million for the three months ended September 30, 2021, an increase of $45 million, or 90% from $50 million during the same period of 2020. The increase was predominantly the result of higher natural gas prices created by increasing demand. Our natural gas sales net of related purchases were $42 million for the three months ended September 30, 2021 compared to $15 million for the same period of 2020. Electricity sales — Electricity sales increased $22 million to $65 million in the third quarter of 2021 compared to $43 million in the same period of 2020. The increase was predominantly due to higher electricity prices in 2021 resulting from higher natural gas prices as well as reduced hydroelectric generation in California. The following table presents our operating and non-operating expenses for the three months ended September 30, 2021 and 2020: Successor Predecessor Three months ended September 30, Three months ended September 30, 2021 2020 (in millions) Operating expenses Energy operating costs $ 52 $ 41 Gas processing costs 5 5 Non-energy operating costs 133 95 General and administrative expenses 51 64 Depreciation, depletion and amortization 54 89 Asset impairments 25 — Taxes other than on income 36 42 Exploration expense 2 2 Purchased natural gas expense 53 35 Electricity generation expenses 29 17 Transportation costs 11 10 Accretion expense 13 10 Other operating expenses, net 4 12 Total operating expenses 468 422 Gain on asset divestitures (2) — Operating income (loss) 122 (13) Non-operating (expenses) income Reorganization items, net (1) 66 Interest and debt expense, net (14) (28) Other non-operating expenses, net — (32) Net income (loss) before taxes $ 107 $ (7) Energy operating costs — Energy operating costs for the three months ended September 30, 2021 were $52 million, which was an increase of $11 million or 27% from $41 million for the same period of 2020. This increase was primarily a result of higher prices for purchased natural gas, which we used to generate electricity for our operations, and for purchased electricity. 31 Non-energy operating costs — Non-energy operating costs for the three months ended September 30, 2021 were $133 million, which was an increase of $38 million or 40% from $95 million for the same period of 2020. This increase was primarily a result of higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells and surface maintenance activity. Additionally, non-energy operating costs increased in 2021 due to higher prices for purchased natural gas which we use to generate steam for our steamfloods. Partially offsetting these increases were lower compensation-related costs from headcount reductions in late 2020 and early 2021 and reduced employee benefits in the second quarter of 2021. Our third quarter 2020 results reflect cost savings for streamlining our operations in response to the industry downturn resulting from the COVID-19 pandemic. Although higher natural gas prices in 2021 increased our operating costs, higher prices have a net positive effect on our operating results due to higher revenue from sales of this commodity which we also produce. General and administrative expenses — Our general and administrative (G&A) expenses were $51 million for the three months ended September 30, 2021, which was a decrease of $13 million from $64 million for the three months ended September 30, 2020. The decrease in G&A expenses reflects lower compensation-related costs primarily due to workforce reductions that occurred in the second half of 2020 and the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. The remaining decrease between comparative periods was primarily due to cost saving efforts which resulted in lower spend across a number of cost categories. The decrease was partially offset by non-cash stock-based compensation expense related to awards granted to executives and directors in 2021. Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $35 million to $54 million in the third quarter of 2021 compared to $89 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment. Asset impairments — We recorded an impairment charge of $25 million for the three months ended September 30, 2021 related to the write-down of a commercial office building located in Bakersfield, California to fair market value. The decline in asset value primarily relates to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic. No impairment charges were recorded for the same period in 2020. See Part I, Item 1 – Financial Statements, Note 13 Asset Impairments for additional information. Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. This expense amounted to $53 million for the three months ended September 30, 2021, which was an increase of $18 million or 51% from $35 million for the same period in 2020. The increase was predominantly the result of higher natural gas prices. Electricity generation expenses — Electricity generation expenses increased from $17 million for the three months ended September 30, 2020 to $29 million in the same period of 2021. The increase was primarily a result of higher prices for natural gas used in electricity generation. Reorganization items, net — Reorganization items, net decreased by $67 million to $1 million of expense for the three months ended September 30, 2021 from $66 million of income during the same period of 2020. We recognized $66 million of income in the third quarter of 2020 primarily due to the write-off of the unamortized balance of deferred gain and issuance costs on our long-term debt at the time of filing our bankruptcy petition on July 15, 2020. The gain was partially offset by legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings. Interest and debt expense, net — Interest and debt expense, net decreased to $14 million in the third quarter of 2021 compared to $28 million in the same period of 2020 primarily due to a decrease in our overall level of debt following our emergence from bankruptcy on October 27, 2020. There were no amounts drawn on our Revolving Credit Facility during the three months ended September 30, 2021. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions. 32 Other non-operating expense, net — Other non-operating expense, net decreased $32 million to zero for the three months ended September 30, 2021. The decrease was primarily due to the significant legal, professional and other fees incurred in preparation for our Chapter 11 filing in 2020. Nine Months Ended September 30, 2021 vs. 2020 The following table presents our operating revenues for the nine months ended September 30, 2021 and 2020: Successor Predecessor Nine months ended September 30, Nine months ended September 30, 2021 2020 (in millions) Oil, natural gas and NGL sales $ 1,459 $ 987 Net (loss) gain from commodity derivatives (603) 75 Sales of purchased natural gas 241 109 Electricity sales 131 75 Other revenue 27 12 Total operating revenues $ 1,255 $ 1,258 Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of derivative settlements, were $1,459 million for the nine months ended September 30, 2021, which is an increase of $472 million compared to $987 million for the same period of 2020. The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table: Oil NGLs Natural Gas Total (in millions) Nine months ended September 30, 2020 $ 795 $ 94 $ 98 $ 987 Changes in realized prices 508 89 78 675 Changes in production (179) (9) (15) (203) Nine months ended September 30, 2021 $ 1,124 $ 174 $ 161 $ 1,459 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. The effect of settlements on our commodity derivatives is not included in the table above. Payments for derivative settlements were $220 million for the nine months ended September 30, 2021 compared to proceeds of $105 million, including $63 million of proceeds from commodity derivative contracts sold prior to maturity, in the first quarter of 2020. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $147 million or 13% compared to the same prior-year period. Net (loss) gain from commodity derivatives — Net loss from commodity derivatives was $603 million for the nine months ended September 30, 2021 compared to a net gain of $75 million in the same period of 2020 as shown in the table below. The non-cash changes in the fair value of our outstanding commodity derivatives resulted from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward curves. Nine months ended September 30, Nine months ended September 30, 2021 2020 (in millions) Non-cash commodity derivative loss, excluding noncontrolling interest $ (383) $ (31) Non-cash commodity derivative gain, noncontrolling interest — 1 Total non-cash changes (383) (30) Net (payments) proceeds on settled commodity derivatives (220) 42 Net proceeds on commodity derivative contracts sold prior to maturity — 63 Net (loss) gain from commodity derivatives $ (603) $ 75 33 Sales of purchased natural gas — Sales of purchased natural gas were $241 million for the nine months ended September 30, 2021, an increase of $132 million, or 121% from $109 million during the same period of 2020. The increase was predominantly the result of higher natural gas prices created by increased demand in 2021 compared to 2020. Our natural gas sales net of related purchases were $97 million for the nine months ended September 30, 2021 compared to $42 million for the same period of 2020. Electricity sales — Electricity sales increased by $56 million to $131 million in the first nine months of 2021 compared to $75 million in the same period of 2020. Electricity sales increased in the first nine months of 2021 from the prior year period as a result of higher natural gas prices due in part to reduced hydroelectric generation in California. In the first nine months of 2020, sales volumes were also lower from planned maintenance and an outage at the Elk Hills power plant. Other revenue — Other revenue increased by $15 million to $27 million in the first nine months of 2021 compared to $12 million in the same period of 2020. The increase was primarily driven by higher revenues from wet gas and processing fee income caused by higher natural gas prices. The following table presents our operating and non-operating expenses for the nine months ended September 30, 2021 and 2020: Successor Predecessor Nine months ended September 30, Nine months ended September 30, 2021 2020 (in millions) Operating expenses Energy operating costs $ 137 $ 118 Gas processing costs 16 17 Non-energy operating costs 370 325 General and administrative expenses 147 193 Depreciation, depletion and amortization 160 296 Asset impairments 28 1,736 Taxes other than on income 113 121 Exploration expense 6 9 Purchased natural gas expense 144 67 Electricity generation expenses 70 47 Transportation costs 37 31 Accretion expense 39 30 Other operating expenses, net 31 45 Total operating expenses 1,298 3,035 Gain on asset divestitures (4) — Operating loss (39) (1,777) Non-operating (expenses) income Reorganization items, net (5) 66 Interest and debt expense, net (40) (200) Net (loss) gain on early extinguishment of debt (2) 5 Other non-operating expenses, net (3) (93) Net loss before taxes $ (89) $ (1,999) Energy operating costs — Energy operating costs for the nine months ended September 30, 2021 were $137 million, which was an increase of $19 million or 16% from $118 million for the same period of 2020. This increase was primarily a result of higher prices for purchased natural gas, which we used to generate electricity for our operations, and for purchased electricity. 34 Non-energy operating costs — Non-energy operating costs for the nine months ended September 30, 2021 were $370 million, which was an increase of $45 million or 14% from $325 million for the same period of 2020. This increase was primarily a result of higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells and surface maintenance activity. Additionally, non-energy operating costs increased in 2021 due to higher prices for natural gas, which we use to generate steam for our steamfloods. Partially offsetting these increases were lower compensation-related costs from headcount reductions in late 2020 and early 2021 and reduced employee benefits in the second quarter of 2021. Although higher natural gas prices in 2021 increased our operating costs, higher prices have a net positive effect on our operating results due to higher revenue from sales of this commodity which we also produce. General and administrative expenses — Our general and administrative (G&A) expenses were $147 million for the nine months ended September 30, 2021, which was a decrease of $46 million from $193 million for the nine months ended September 30, 2020. The decrease in G&A expenses was primarily attributable to lower compensation-related costs as a result of workforce reductions that occurred in the second half of 2020 and the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. The remaining decrease was primarily due to cost savings efforts which resulted in lower spend across a number of cost categories. The decrease was partially offset by an increase in non-cash stock-based compensation expense related to awards granted to executives and directors in 2021. Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $136 million to $160 million in the first nine months of 2021 compared to $296 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment. Asset impairments — Asset impairment charges for the nine months ended September 30, 2021 were $28 million including a write-down of commercial office space in Bakersfield, California to fair value and the write-off of capitalized costs related to projects which were abandoned. The decline in value of the commercial office building primarily relates to limited demand for office space of this size and type in the Bakersfield market and general trends in commercial real estate due to the COVID-19 pandemic. For the same period in 2020, we recorded an impairment charge of $1.7 billion due to the sharp drop in commodity prices in March 2020, which included $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that was no longer included in our development plans at that time. See Part I, Item 1 – Financial Statements, Note 13 Asset Impairments for additional information. Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. This expense amounted to $144 million for the nine months ended September 30, 2021, which was an increase of $77 million or 115% from $67 million for the same period in 2020. The change was predominantly the result of higher natural gas prices. Electricity generation expenses — Electricity cost of sales increased from $47 million in the first nine months of 2020 to $70 million in the same period of 2021. The increase was primarily a result of higher pricing on purchased natural gas. Other operating expenses, net — Other expenses, net was $31 million for the nine months ended September 30, 2021, which was a decrease of $14 million from $45 million during the same period of 2020. The first nine months of 2020 included a one-time payment of $20 million made in connection with an expiring pipeline delivery contract and $7 million related to an outage at the Elk Hills power plant. The first nine months of 2021 included $15 million in severance costs. Reorganization items, net — Reorganization items, net was $5 million of expense for the nine months ended September 30, 2021 which was a decrease of $71 million from $66 million of income during the same period of 2020. We recognized $66 million of income in the third quarter of 2020 primarily due to the write-off of the unamortized balance of our deferred gain and issuance costs on our long-term debt at the time of filing our bankruptcy petition on July 15, 2020 which was partially offset by legal, professional and other fees, including debtor-in-possession financing costs, all of which related to our bankruptcy proceedings. 35 Interest and debt expense, net — Interest and debt expense, net decreased $160 million to $40 million in the first nine months of 2021 compared to $200 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from bankruptcy on October 27, 2020. Additionally, in the first quarter of 2021, we paid off our Revolving Credit Facility and had no balance drawn during either the second or third quarter. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions. Other non-operating expense, net — Other non-operating expense, net decreased $90 million to $3 million for the nine months ended September 30, 2021 compared to $93 million in the same period for 2020. The higher expense in the first nine months of 2020 was primarily a result of legal, professional and other fees related to our bankruptcy filing and an abandoned financing transaction. Liquidity and Capital Resources Cash Flow Analysis Cash flows from operating activities — Our net cash provided by operating activities is sensitive to many variables, including changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. For the three months ended September 30, 2021, our operating cash flow increased 279%, or $134 million, to $182 million from $48 million in the same prior period of 2020. For the nine months ended September 30, 2021, our operating cash flow increased 223%, or $315 million, to $456 million from $141 million in the same period of 2020. The increase in operating cash flow for both the three and nine months ended September 30, 2021 primarily relates to higher average realized prices (including the effects of settlements on our commodity derivatives) in 2021 compared to the same prior-year periods. Average realized prices increased primarily due to the economic recovery as COVID-19 related mobility restrictions were lifted and demand increased. This increase was partially offset by lower production volumes in 2021 as compared to the same periods in 2020. In the third quarter of 2021, we purchased $24 million of greenhouse gas allowances of which $6 million was for our fourth quarter of 2021 obligation and $18 million was a prepayment for our 2022 compliance obligation. This prepayment is included in our working capital changes on our condensed consolidated statements of cash flows for the three and nine months ended September 30, 2021. Cash flows from investing activities — Our net cash used in investing activities increased $87 million from $1 million for the three months ended September 30, 2020 to $88 million for the same period in 2021. Our net cash used in investing activities increased $123 million from $28 million for the nine months ended September 30, 2020 to $151 million for the same period in 2021. 36 The increased use of cash for investing activities in 2021 primarily relates to higher capital investment and our acquisition of working interests in certain joint venture wells held by MIRA. Investing activities in 2020 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. Proceeds of $13 million from non-core asset sales for the nine months ended September 30, 2021 primarily related to the sale of unimproved land. The table below summarizes net cash used in investing activities for the three and nine months ended September 30, 2021 and 2020 (in millions): Successor Predecessor Successor Predecessor Three months ended September 30, 2021 Three Months Ended September 30, 2020 Nine months ended September 30, 2021 Nine Months Ended September 30, 2020 (in millions) Capital investments $ (51) $ (4) $ (128) $ (37) Changes in capital investment accruals 5 3 18 (25) Proceeds from divestitures 11 — 13 41 Acquisitions (53) — (53) — Other — — (1) (7) Net cash used in investing activities $ (88) $ (1) $ (151) $ (28) Cash flows from financing activities — Our net cash used in financing activities was $56 million for the three months ended September 30, 2021 compared to net cash used in financing activities of $51 million for the same period of 2020. Our net cash used in financing activities was $144 million for the nine months ended September 30, 2021 compared to net cash used in financing activities of $8 million for the same period of 2020. Financing activities for the three and nine months ended September 30, 2021 included repurchases of common stock under our Share Repurchase Program. Financing cash outflows related to debt transactions for the nine months ended September 30, 2020 included $733 million in net borrowings under our debtor-in-possession facilities partially offset by $518 million in net repayments on our then outstanding revolving credit facility, $100 million for the repayment of our 2020 Senior Notes at maturity, $25 million for debtor-in-possession financing costs and $3 million for open market purchases of our then outstanding Second Lien Notes. The table below summarizes net cash used by financing activities for the three and nine months ended September 30, 2021 and 2020 (in millions): Successor Predecessor Successor Predecessor Three months ended September 30, 2021 Three Months Ended September 30, 2020 Nine months ended September 30, 2021 Nine Months Ended September 30, 2020 (in millions) Debt transactions, net $ — $ (23) $ (12) $ 87 Distributions to noncontrolling interest holders, net (19) (28) (50) (94) Repurchases of common stock (39) — (84) — Proceeds from warrants exercised 2 — 2 — Other — — — (1) Net cash used in financing activities $ (56) $ (51) $ (144) $ (8) Liquidity Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the first nine months of 2021 was for capital investment, distributions to a noncontrolling interest holder, acquisition of working interests from MIRA and repurchases of our common stock. 37 In November 2021, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.2 billion. At current commodity prices and our planned 2021 capital program described below, we expect to generate positive free cash flow, which we may use (i) to increase investments in our drilling program to accelerate value, (ii) to pay dividends or buy back stock to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, (iii) to maintain cash on our balance sheet, or (iv) for other corporate purposes. We expect to begin paying income taxes in 2022 if Brent prices remain at current levels for a sustained period. Our tax paying status depends on a number of factors, including but not limited to, commodity prices, the amount and type of our capital spend, cost structure and activity levels. Potential legislation could change key provisions of the existing U.S. corporate income tax regime and it is uncertain whether some or all of the legislative proposals will be enacted. We do not currently expect the proposed modifications will materially impact our income tax liability. We believe we have sufficient sources of cash to meet our obligations for the next twelve months. The following table summarizes our liquidity (in millions): Successor September 30, 2021 (in millions) Cash $ 189 Revolving Credit Facility: Borrowing capacity 492 Outstanding letters of credit (133) Availability $ 359 Liquidity $ 548 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. Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three or nine months ended September 30, 2021. See Part I, Item 1 – Financial Statements, Note 9 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of September 30, 2021. 2021 Capital Program Our capital program will be dynamic in response to oil market volatility while focusing on maintaining our oil production and strong liquidity and maximizing our free cash flow. We entered 2021 with an internally funded capital program of $200 million – $225 million. In the second quarter of 2021, we reallocated drilling capital to downhole maintenance activities which reduced our full year outlook to $170 million – $190 million. Success of the drilling program to date, along with the rise in commodity prices, resulted in the addition of a drilling rig in the fourth quarter of 2021 that was planned for 2022. As a result, we expect our full year capital program to range from $180 – $200 million. Any curtailment of the development of our properties will lead to a decline in our production and may lower our reserves. A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets. 38 The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals (in millions): Successor 2021 Full Year Estimate Nine months ended September 30, 2021 (in millions) Drilling $110 - $120 $73 Capital workovers 25 - 30 25 Infrastructure, corporate and other 45 - 50 30 Total $180 - $200 $128 Regulatory Update In April 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division (CalGEM) to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045. In May 2021, CalGEM published the proposed rule to end the issuance of new permits for well stimulation treatments. Since the Governor’s announcement, CalGem has not issued any approvals for well stimulation treatments. We expect little to no impact on future development activities because we are not dependent on well stimulation treatments. Less than 1% of our proved reserves require well stimulation and our current long-term development plans do not include well stimulation. In October 2021, CalGEM released for public comment a draft rule to update its public health regulations. Among other changes, the draft includes a proposed setback of 3,200 feet for new wells with new surface locations from sensitive receptors, such as residences, schools and health care facilities. The draft is subject to public comment and the rulemaking process. It is anticipated that a version of the draft rule will be adopted in the next 12 to 24 months. We expect little to no impact on our long-term development plans because our development strategy does not rely on a significant number of new wells with new surface locations in affected setback areas. Dividends On November 11, 2021, our Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2021 and is expected to be paid on December 16, 2021. This quarterly dividend is made pursuant to a cash dividend policy approved by the Board of Directors, which anticipates a total annual dividend of $0.68, payable in quarterly increments of $0.17 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. The aggregate payment for this dividend will be approximately $14 million. We anticipate our next dividend will be paid in the first quarter of 2022. Based on the current number of our outstanding shares, we expect to make aggregate annual dividend payments of approximately $56 million. Share Repurchase Program Our Board of Directors authorized a Share Repurchase Program for up to $250 million through March 31, 2022. As of September 30, 2021, we repurchased 2.6 million shares of our common stock, at an average price of $32.39 per share, through either open market purchases or a Rule 10b5-1 plan at an aggregate cost of $84 million. Shares repurchased were held as treasury stock as of September 30, 2021. On November 11, 2021, our Board of Directors extended the time period for our Share Repurchase Program through June 30, 2022. 39 Divestitures After the quarter-end, closings for the sale of our Ventura basin operations occurred with respect to the majority of the basin's assets and subsequent closings are expected to occur in the following quarters. See Part I, Item 1 – Financial Statements, Note 6 Assets Held for Sale for more information regarding this transaction. During the three months ended September 30, 2021, we sold unimproved land for $11 million in proceeds recognizing a $2 million gain. During the nine months ended September 30, 2021 we sold non-core assets, including unimproved land, for $13 million in proceeds recognizing a $4 million gain. Acquisitions and Joint Ventures In the third quarter of 2021, we completed the wind-up of our development joint venture (JV) with MIRA and our development joint venture with Benefit Street Partners (BSP). In August 2021, we purchased MIRA’s entire working interest share in the conveyed assets for $53 million, before purchase price adjustments and transaction costs. Prior to the acquisition, our consolidated results reflect only our 10% working interest share in the productive wells. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on our MIRA JV. In September 2021, BSP's preferred interest in the BSP JV was automatically redeemed in full under the terms of the joint venture agreement. Prior to the redemption, we made aggregate distributions to BSP of $50 million in 2021 which reduced noncontrolling interest on our condensed consolidated balance sheet and was recorded as a financing cash outflow on our condensed consolidated statements of cash flows for the nine months ended September 30, 2021. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on our BSP JV. 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. Fixed and Variable Costs Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. 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. The measures taken to address the industry downturn in the prior year demonstrate that we can significantly reduce our operating costs in response to prevailing market conditions. We further believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs in a safe and responsible manner throughout their lifecycles. 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. 40 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, 2021 and December 31, 2020 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 cannot be accurately determined. In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement (BSEE) determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with a 37.5% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time and is challenging BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy and will be challenging the order from BSEE. See Part I, Item 1 – Financial Statements, Note 8 Lawsuits, Claims, Commitments and Contingencies for further information. Significant Accounting and Disclosure Changes See Part I, Item 1 – Financial Statements, Note 2 Accounting and Disclosure Changes for a discussion of new accounting matters. 41 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. These statements are not promises or guarantees of future conduct, performance or policy and 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 • operations and operational results including production, hedging and capital investment • budgets and maintenance capital requirements • reserves and reservoir characteristics • type curves • expected synergies from acquisitions and joint ventures • energy transition initiatives 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. Therefore, the actual conduct of our activities, including development, implementation, or continuation of any carbon capture and storage programs or other initiatives or efforts discussed or forecasted in this report or in the future in connection with updates issued regarding these programs, initiatives and efforts, may differ materially in the future. Factors (but not necessarily all the factors) that could cause results to differ include: • our ability to execute our business plan post-emergence, including our ability to finance and implement our carbon storage program; • our ability to realize the benefits of business strategies and initiatives related to energy transition, including carbon capture and storage projects and other renewable energy efforts; • global socio-demographic and economic trends and technological innovations; • the volatility of commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices; • impact of our recent emergence from bankruptcy on our business and relationships; • debt limitations on our financial flexibility; • insufficient cash flow to fund planned investments, interest payments on our debt, debt repurchases or changes to our capital plan; • insufficient capital or liquidity, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors; • 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; • legislative or regulatory changes, including those related to (i) drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) managing energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) protection of health, safety and the environment, (iv) tax credits or other incentives, or (v) 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; • changes in our dividend policy and our ability to declare future dividends; • production-sharing contracts’ effects on production and unit operating costs; • our ability to successfully gather and verify data regarding our environmental impacts and initiatives; • the compliance of various third parties with our policies and procedures and legal requirements as well as contracts we enter into in connection with our climate-related initiatives; • the effect of our stock price on costs associated with incentive compensation; • effects of hedging transactions; • equipment, service or labor price inflation or unavailability; 42 • 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; • climate-related conditions and weather events • 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; • other factors discussed in Item 1A, Risk Factors in our 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. This report may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information. 43