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. Chapter 11 Proceedings On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases). On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new equity owners and a significantly improved financial position. Fresh Start Accounting We qualified for and adopted fresh start accounting upon emergence from bankruptcy at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting. Organization Changes In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions, making progress towards our lower cost operating model. We changed our 2021 capital guidance to reallocate investments to downhole maintenance activities, which will result in an increase in estimated 2021 operating costs. As a result, we expect our sustainable cost savings in general and administrative expense and operating costs to be $80 million in 2021 as compared to 2020 levels. We believe the steps taken to date have improved our financial condition and streamlined our business. In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020. On December 31, 2020, our former President, Chief Executive Officer and director Todd A. Stevens departed and Mark A. (Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors. On March 22, 2021, the Board of Directors appointed Mr. McFarland as President and Chief Executive Officer on a permanent basis. On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr. McFarland as the Chair of our Board of Directors. Mr. McFarland will continue to serve as a director. Recent Debt Transactions In January 2021, we completed a private offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and our EHP Notes, with the remaining proceeds used to pay down a portion of the outstanding borrowings under our Revolving Credit Facility. For more information on the terms of Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 5 Debt. 21 In May 2021, we amended the Revolving Credit Facility to: • increase our borrowing base from $1.167 billion to $1.2 billion; • evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million; • increase our capacity to make certain restricted payments; • reduce the minimum amount of hedges that we are required to maintain for a rolling 24 month period on reasonably anticipated forecasted crude oil production from 50% to 33% so long as our total net leverage ratio is less than 2.00:1.00; and • increase our maximum hedging limitation to 85% (and permit purchased puts and floors up to 100%) of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids for a 48-month period. Share Repurchase Program In May 2021, our Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of our common stock through March 31, 2022. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The SRP does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. Business Environment and Industry Outlook Commodity Prices Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and 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 gradually increased beginning in October 2020 through the first quarter of 2021. Benchmark prices for Brent crude oil in the first quarter of 2021 increased approximately 35% from the fourth quarter of 2020 demonstrating a strong recovery from the prior year when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) pandemic. Current pricing has benefited from the gradual re-opening of the economy and the lifting of restrictions related to the COVID-19 pandemic. Further, members of Organization of Petroleum Exporting Countries (OPEC) and non-OPEC producers have restrained crude oil production attempting to reduce oil supplies built during the worst period of the pandemic. The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2021, December 31, 2020 and March 31, 2020: Three months ended March 31, Three months ended December 31, Three months ended March 31, 2021 2020 2020 Brent oil ($/Bbl) $ 61.10 $ 45.24 $ 50.96 WTI oil ($/Bbl) $ 57.84 $ 42.66 $ 46.17 NYMEX gas ($/MMBtu) $ 2.72 $ 2.66 $ 2.05 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. 22 Recent Developments Certain actions of the new U.S. administration could impact the oil and gas industry. Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production. Such outcomes could materially and adversely affect our business, results of operations and financial condition. On April 23, 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045. This marks a reversal from the governor’s previous statements that he lacked the executive authority to ban hydraulic fracturing, and any decision to prohibit the extraction of oil would likely be subject to significant opposition and legal challenge. Regardless of whether or not such a ban is upheld, we expect little to no impact on future development activities because we are not dependent on well stimulation treatments. Less than 1% of our proved reserves require well stimulation and our current long-term development plans do not include well stimulation. Operations We have the largest privately held oil and natural gas mineral acreage position in California, consisting of 2.1 million net mineral acres spanning four of California's major oil and natural gas basins. We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. Approximately 65% of our mineral acreage is held in fee and the remainder is leased. Of our leased acreage, approximately 50% is held by production and the remainder is subject to lease expiration if initial producing wells are not drilled within a specified period of time. The primary terms of our leases range from one to ten years. The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained. As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells in response to a low commodity price environment while retaining our oil and gas leases which are held by production. With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities. We also own or control a network of integrated infrastructure that complements our operations including gas processing plants, oil and gas gathering systems, power plants and other related assets. Our strategically located infrastructure helps us maximize the value generated from our production. Beyond our essential role in supplying Californians with oil, natural gas, NGLs and electricity, our 2030 Sustainability Goal for carbon is to design and permit California’s first carbon capture and sequestration system by mid-decade which is expected to reduce carbon emissions associated with our operations and significantly extend the productive life of our Elk Hills field. Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and 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 16% of our net production for the three months ended March 31, 2021. 23 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. Marketing Arrangements We own a large and geographically diverse portfolio of assets that generate the following revenue streams: Crude Oil — We sell almost all of our crude oil into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S. regions. Substantially all of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements. Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong. California is heavily reliant on imported sources of energy, with approximately 70% of oil and 90% of natural gas consumed in 2019 imported from outside the state. 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 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 daily basis at average monthly index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity in the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada. As a result, we typically enjoy higher netback pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and approximately 11% of our revenue from oil, natural gas and NGL sales are from natural gas. In addition to selling our produced natural gas, we also purchase natural gas for use in steam generation for our steamfloods and power generation. The positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to more volumes sold than used. Conversely, lower natural gas prices lower our operating costs but have a net negative effect on our financial results. We currently have transportation capacity contracts to transport the majority of our natural gas volumes until September 2023. Natural Gas Liquid (NGL) — NGL price realizations are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints and seasonality can magnify price volatility. Our earnings are also affected by the performance of our complementary natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. 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 through March 2023. Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped. We have thus far met all of our shipping commitments under this contract. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 30% of our NGLs are sold to export markets. 24 Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces field operating costs and provides a reliable source of power. We sell the excess electricity generated to a local utility, other third parties and the grid. The power sold to the utility is subject to an agreement through the end of 2023, which includes a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Any excess capacity not sold to other third parties is sold to the wholesale power market. The prices obtained for excess power impact our earnings but generally by a relatively small amount. Hedging Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred on the Effective Date, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges. We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report if our leverage ratio is greater than 2.00:1.00. If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are required to maintain is reduced from 50% to 33%. Currently, we may not hedge more than 85% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period. In the three months ended March 31, 2021, we added hedges on one million barrels of production for the period from April 2021 to March 2022 at a weighted-average Brent price of approximately $61 per barrel. See Liquidity and Capital Resources below for a current table summarizing our outstanding derivative contracts. 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. 25 Production and Prices The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2021 and 2020: Successor Predecessor Three months ended March 31, Three months ended March 31, 2021 2020 Oil (MBbl/d) San Joaquin Basin 38 47 Los Angeles Basin 20 26 Ventura Basin 2 4 Total 60 77 NGLs (MBbl/d) San Joaquin Basin 12 14 Ventura Basin — — Total 12 14 Natural gas (MMcf/d) San Joaquin Basin 135 152 Los Angeles Basin 1 2 Ventura Basin 4 6 Sacramento Basin 20 23 Total 160 183 Total Net Production (MBoe/d) 99 121 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 March 31, 2021 compared to the same period in 2020, total daily production decreased by approximately 22 MBoe/d or 18%. The decrease in production largely resulted from limited drilling and capital investment during the prior 12 months. Our average drilling rigs decreased from 7 in the three months ended March 31, 2020 to 1 rig in the three months ended March 31, 2021. In addition, production was also negatively impacted by 1 MBoe/d in the first quarter of 2021 compared to 2020 due to downtime at one of our gas processing plants. Our PSC-type contracts negatively impacted our oil production in the first quarter of 2021 by approximately 3 MBoe/d compared to the same period in 2020. Our total daily production decreased by approximately 15% compared to the same period in 2020 after excluding the impact of PSC-type contracts and unscheduled downtime at one of our natural gas processing plants. 26 The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three months ended March 31, 2021 and 2020: Successor Predecessor Three months ended March 31, Three months ended March 31, 2021 2020 Price Realization Price Realization Oil ($ per Bbl) Brent $ 61.10 $ 50.96 Realized price without hedge $ 60.81 100% $ 50.78 100% Settled hedges (7.08) 4.72 Realized price with hedge $ 53.73 88% $ 55.50 109% WTI $ 57.84 $ 46.17 Realized price without hedge $ 60.81 105% $ 50.78 110% Realized price with hedge $ 53.73 93% $ 55.50 120% NGLs ($ per Bbl) Realized price (% of Brent) $ 48.77 80% $ 29.28 57% Realized price (% of WTI) $ 48.77 84% $ 29.28 63% Natural gas NYMEX ($/MMBtu) $ 2.72 $ 2.05 Realized price without hedge ($/Mcf) $ 3.29 121% $ 2.25 110% Settled hedges (0.04) 0.10 Realized price with hedge ($/Mcf) $ 3.25 119% $ 2.35 115% Oil — Brent index and realized prices without hedge settlements were higher in the three months ended March 31, 2021 compared to the same prior-year period due to a recovery in oil demand from the severe demand decline caused by COVID-19 in 2020. Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing restrictions and the significant production curtailments by OPEC members and Russia. Further, most producers in other nations also curtailed production and significantly reduced their capital investments in response to COVID-19 in 2020, which continued into 2021. NGLs — Prices for NGLs increased for the three months ended March 31, 2021 compared to the same period in 2020 as supply in 2020 outpaced demand, causing lower NGL prices in the first quarter of 2020. In the first quarter of 2021, producers continued to curtail production and the tighter supply resulted in higher benchmark prices and price realizations as compared to the same prior year period. Natural Gas — Our natural gas realized prices were higher in the three months ended March 31, 2021 than the comparable period of 2020 due to increased natural gas demand in the nationwide markets. This was a significant change from the first quarter of 2020 in which demand decreased as a result of shelter-in-place orders related to COVID-19. 27 Statements of Operations Analysis We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the implementation of the Plan, our results of operations for the Successor period may not be comparable with that of the Predecessor period. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020. Results of Oil and Gas Operations The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended March 31, 2021 and 2020: Successor Predecessor Three months ended March 31, Three months ended March 31, 2021 2020 Energy operating costs (a) $ 4.70 $ 3.71 Gas processing costs 0.53 0.67 Non-energy operating costs (b) 13.10 13.00 Operating costs $ 18.33 $ 17.38 Operating costs, excluding effects of PSC-type contracts (c) $ 16.72 $ 16.48 Field general and administrative expenses (d) $ 0.89 $ 1.09 Field depreciation, depletion and amortization (d)(e) $ 5.14 $ 10.05 Field taxes other than on income (d) $ 3.46 $ 3.08 (a) Energy operating costs include purchases of fuel gas and electricity used in our operations and internal costs to produce electricity used in our fields. (b) Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. (c) As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. These amounts represent our operating costs after adjusting for this difference. (d) Excludes corporate expenses. (e) Field depreciation, depletion and amortization decreased in the three months ended March 31, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the fresh start valuation of our property, plant and equipment. 28 Consolidated Results of Operations The following table presents our consolidated results of operations and key financial measures for the three months ended March 31, 2021 and 2020: Successor Predecessor Three months ended March 31, Three months ended March 31, 2021 2020 (in millions) Oil, natural gas and NGL sales $ 432 $ 430 Net derivative (loss) gain from commodity contracts (213) 79 Trading revenue 98 45 Electricity sales 33 13 Other revenue 13 6 Operating costs (164) (192) General and administrative expenses (48) (60) Depreciation, depletion and amortization (52) (119) Asset impairments (3) (1,736) Taxes other than on income (40) (41) Exploration expense (2) (5) Trading costs (61) (24) Electricity cost of sales (24) (16) Transportation costs (12) (13) Other expenses, net (30) (16) Reorganization items (2) — Interest and debt expense, net (13) (87) Net gain on early extinguishment of debt (2) 5 Gain on asset divestitures 2 — Other non-operating expenses (1) (14) Loss before income taxes (89) (1,745) Income tax — — Net loss (89) (1,745) Net income attributable to noncontrolling interests (5) (51) Net loss attributable to common stock $ (94) $ (1,796) Three months ended March 31, 2021 vs. 2020 Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $432 million for the three months ended March 31, 2021, which is an increase of $2 million compared to $430 million for the same period of 2020. The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table: Oil NGLs Natural Gas Total (in millions) Three months ended March 31, 2020 $ 356 $ 36 $ 38 $ 430 Changes in realized prices 71 24 18 113 Changes in production (96) (6) (9) (111) Three months ended March 31, 2021 $ 331 $ 54 $ 47 $ 432 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. Payments for settled hedges were $39 million for the three months ended March 31, 2021 compared to proceeds of $98 million, including $63 million of proceeds from derivative contracts sold prior to maturity, for the same period of 2020. Including the effect of settled hedges, our oil, natural gas and NGL revenue decreased by $135 million or 26% compared to the same prior-year period. 29 Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $213 million for the three months ended March 31, 2021 compared to a net gain of $79 million in the same period of 2020. The non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices and the associated forward curves. Three months ended March 31, Three months ended March 31, 2021 2020 (in millions) Non-cash derivative (loss), excluding noncontrolling interest $ (174) $ (35) Non-cash derivative gain, noncontrolling interest — 16 Total non-cash changes (174) (19) Net (payments) proceeds on settled commodity derivatives (39) 35 Net proceeds on derivative contracts sold prior to maturity — 63 Net derivative (loss) gain from commodity contracts $ (213) $ 79 Trading revenue – Trading revenue was $98 million for the three months ended March 31, 2021, an increase of $53 million, or 118% from $45 million during the same period of 2020. The increase was predominantly the result of higher volume and prices related to our natural gas trading activities. Our net profit from natural gas trading activities, after consideration of trading costs described below, was $37 million for the three months ended March 31, 2021 compared to $21 million for the same period of 2020. Electricity sales – Electricity sales increased $20 million to $33 million in the first quarter of 2021 compared to $13 million in the same period of 2020. There were lower electricity sales in the first quarter of 2020 as a result of planned major maintenance at the Elk Hills power plant. Operating costs — Operating costs for the three months ended March 31, 2021 were $164 million, which was a decrease of $28 million or 15% from $192 million for the same period of 2020. The decrease was primarily attributable to efficiencies and streamlining of our operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021. General and administrative expenses — Our general and administrative (G&A) expenses were $48 million for the three months ended March 31, 2021, which was a decrease of $12 million from $60 million for the three months ended March 31, 2020. The decrease in G&A expenses were attributable to efficiencies and streamlining of our operations, including a decrease of $7 million in employee related expenses as a result of workforce reductions. Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $67 million to $52 million in the first quarter of 2021 compared to $119 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment. Asset impairments – Asset impairment charges for the three months ended March 31, 2021 were $3 million for the impairment of capitalized costs related to projects which were abandoned. For the same period in 2020, we recorded an impairment charge of $1.7 billion due to the sharp drop in commodity prices in March 2020, which included $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that was no longer included in our development plans at that time. See Part I, Item 1 – Financial Statements, Note 14 Asset Impairments for additional information. Trading costs – Natural gas purchases related to trading activities were $61 million for the three months ended March 31, 2021, which was an increase of $37 million or 154% from $24 million for the same period in 2020. The change was predominantly the result of higher activity levels and prices related to natural gas trading activities. Other expenses, net – Other expenses, net was $30 million for the three months ended March 31, 2021, which was an increase of $14 million from $16 million during the same period of 2020. The increase was largely the result of a restructuring charge related to workforce reductions in the three months ended March 31, 2021. 30 Interest and debt expense, net — Interest and debt expense, net decreased $74 million to $13 million in the first quarter of 2021 compared to $87 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from bankruptcy. Additionally, in the first quarter of 2021, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn for two months in the period. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions. Other non-operating expense — Other non-operating expense decreased $13 million to $1 million for the three months ended March 31, 2021 compared to $14 million in the same period for 2020. The expense in the first quarter of 2020 was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, which were incurred prior to our petition date, and abandoned transactions. Net income attributable to noncontrolling interests — Upon emergence from bankruptcy, we acquired all of ECR's member interests in the Ares JV; therefore, the allocation of net income to noncontrolling interest holders in the Successor period for the three months ended March 31, 2021 is lower than the Predecessor period for the three months ended March 31, 2020. See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information on the settlement terms of the Ares JV. Liquidity and Capital Resources Cash Flow Analysis 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 36%, or $81 million, to $147 million for the three months ended March 31, 2021 from $228 million in the same period of 2020. The net change in operating cash flow includes decreases primarily from: (i) settlement payments on our derivative contracts in the first quarter of 2021 compared to proceeds received during the first quarter of 2020 and (ii) a large increase in trade accounts receivable resulting from changes in entry and exit prices between the comparative quarters. These decreases were partially offset by lower (i) operating costs primarily related to workforce reductions, (ii) interest payments on our long-term debt and (iii) payments of variable compensation as a result of changing from an annual payment in the first quarter of 2020 compared to quarterly payments in the first quarter of 2021. Cash flows from investing activities — Our net cash used in investing activities increased $8 million, or 67% from $12 million for the three months ended March 31, 2020 to $20 million for the same period in 2021. Cash used in investing activities included $49 million for capital investment in the three months ended March 31, 2020 compared to $22 million in the three months ended March 31, 2021 due to lower activity levels in 2021. Capital investments were partially offset by $41 million related to royalty interest and non-core asset sales in the first quarter of 2020 as compared to proceeds of $2 million in the first quarter of 2021 for non-core asset sales. The table below summarizes net cash used in investing activities for the three months ended March 31, 2021 and 2020 (in millions): Successor Predecessor Three months ended March 31, 2021 Three months ended March 31, 2020 (in millions) Capital investments $ (27) $ (30) Changes in capital investment accruals 5 (19) Proceeds from divestitures 2 41 Other — (4) Net cash used in investing activities $ (20) $ (12) Cash flows from financing activities — Our net cash used in financing activities of $25 million for the three months ended March 31, 2021 included $14 million of distributions to noncontrolling interest holders and a net $11 million of cash used to repay long-term debt. See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our debt. 31 Our net cash used in financing activities for the three months ended March 31, 2020 was $156 million and primarily included net repayments of $110 million on our debt obligations and $42 million in net distributions to noncontrolling interest holders. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Notes. The table below summarizes net cash used by financing activities for the three months ended March 31, 2021 and 2020 (in millions): Successor Predecessor Three months ended March 31, 2021 Three months ended March 31, 2020 (in millions) Debt transactions, net $ (11) $ (110) Debt repurchases — (3) Distributions to noncontrolling interest holders, net (14) (42) Other — (1) Net cash used by financing activities $ (25) $ (156) 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 emerged from bankruptcy with a strong balance sheet and low leverage. We have substantially revamped our cost structure while maintaining sustainable operations. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. At current commodity prices and our planned 2021 capital program described below, we expect to generate positive free cash flow, which may be used to (i) increase investments in our drilling program to accelerate value, (ii) pay dividends or buy back stock to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, or (iii) maintain cash on our balance sheet. We may be required to begin paying income taxes if Brent prices remain above $60 per barrel for a sustained period. Our tax paying status depends on a number of factors, including but not limited to, potential legislation which could limit tax incentives for fossil fuels, the amount and type of our capital spend, cost structure and activity levels. We believe we have sufficient sources of cash to meet our obligations for the next twelve months. Based on the timing of our anticipated cash distributions to Benefit Street Partners (BSP) at current commodity prices, we believe the preferred interest held by BSP in our development joint venture could be automatically redeemed early in the fourth quarter of 2021. See Part I, Item 1 – Financial Statements, Note 6 Joint Ventures for additional information on our BSP JV. The following table summarizes our liquidity (in millions): Successor March 31, April 30, 2021 2021 (in millions) Unrestricted cash $ 130 $ 123 Revolving Credit Facility: Borrowing capacity (a) 540 492 Letters of credit outstanding (125) (125) Total availability $ 415 $ 367 Liquidity $ 545 $ 490 (a) In April 2021, the aggregate commitment of our lenders was reduced to $492 million based on the terms of our Revolving Credit Facility. See Part I, Item 1 – Financial Statements, Note 5 Debt for more information on our Revolving Credit Facility. 32 Derivatives Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. To mitigate some of the risk inherent in the downward movement in oil prices, we may enter into various derivative instruments to hedge commodity price risk. Commodity Contracts Our Revolving Credit Facility requires us to maintain hedges on a notional amount of crude oil production as described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report. Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2021. At April 30, 2021, we had the following Brent-based crude oil contracts: Q2 2021 Q3 2021 Q4 2021 1H 2022 2H 2022 January - October 2023 Sold Calls Barrels per day 33,537 36,688 37,037 33,842 27,773 17,758 Weighted-average price per barrel $ 48.73 $ 50.47 $ 60.75 $ 60.00 $ 58.62 $ 58.01 Purchased Puts Barrels per day 37,872 36,943 35,820 33,842 27,773 17,758 Weighted-average price per barrel $ 40.00 $ 40.18 $ 40.19 $ 40.00 $ 40.00 $ 40.00 Sold Puts Barrels per day 15,149 14,647 14,193 3,416 2,674 — Weighted-average price per barrel $ 31.41 $ 30.00 $ 32.00 $ 32.00 $ 32.00 $ — Swaps Barrels per day 9,639 10,063 10,922 7,763 6,386 5,919 Weighted-average price per barrel $ 46.35 $ 49.09 $ 51.11 $ 48.17 $ 46.34 $ 47.57 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. • Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel. 2021 Capital Program Our capital program will be dynamic in response to oil market volatility while focusing on maintaining our oil production and strong liquidity and maximizing our free cash flow. We entered 2021 with an internally funded capital program of $200 million to $225 million. During the first quarter of 2021, the 2021 capital program was revised to $185 million to $210 million reflecting a reallocation of drilling capital to downhole maintenance, which provide efficiencies and faster payouts. Our current plan anticipates we will gradually raise quarterly capital investment throughout the year. 33 If commodity prices decline significantly from current levels, we may need to adjust our capital program in response to market conditions. Any curtailment of the development of our properties will lead to a decline in our production and may lower our reserves. A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets. The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals (in millions): 2021 Target Three months ended March 31, 2021 (in millions) Drilling $105 - $120 $ 13 Capital workovers 35 - 40 7 Infrastructure, corporate and other 45 - 50 7 Total $185 - $210 $ 27 Lawsuits, Claims, Commitments and Contingencies 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 March 31, 2021 and December 31, 2020 were not material to our condensed consolidated balance sheets as of such dates. In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with an approximately 35% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. We are currently evaluating this claim. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined. 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. 34 Forward-Looking Statements The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our future: • financial position, liquidity, cash flows and results of operations • business prospects • transactions and projects • operating costs • operations and operational results including production, hedging and capital investment • budgets and maintenance capital requirements • reserves • type curves • expected synergies from acquisitions and joint ventures Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include: • our ability to execute our business plan post-emergence; • the volatility of commodity prices and the potential for sustained low oil, natural gas and 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 drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases (GHGs) or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products; • joint ventures and acquisitions and our ability to achieve expected synergies; • 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; • production-sharing contracts’ effects on production and unit operating costs; • the effect of our stock price on costs associated with incentive compensation; • effects of hedging transactions; • 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; and • factors discussed in Item 1A, Risk Factors in our Annual Report on Form 10-K available at www.crc.com. 35 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. 36 Item 3 Quantitative and Qualitative Disclosures About Market Risk For the three months ended March 31, 2021, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the 2020 Annual Report.