What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-11-12 compared with 2021-08-06 · 348 added, 259 removed, 237 unchanged (72% of the section changed)

4 unchanged sentences

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.

11 unchanged sentences

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 six months ended June 30, 2021 compared to the same periods in 2020.

Benchmark prices for Brent crude oil in the first half of 2021 increased 55% from the same period in 2020 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.

Commodity prices have benefited from rising consumption and economic growth due to the lifting of restrictions related to the COVID-19 pandemic.

During the first half of 2021, members of Organization of Petroleum Exporting Countries (OPEC) continued to restrain crude oil production attempting to reduce oil supplies built during 2020.

The following table presents the average daily Brent, WTI and NYMEX prices for the three and six months ended June 30, 2021 and 2020:

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.

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

June 30, Six months ended

September 30, Nine months ended

September 30,

2021 2020 2021 2020

5 unchanged sentences

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.

The following table sets forth our average net production volumes of oil, natural gas liquids (NGLs) and natural gas per day for the three and six months ended June 30, 2021 and 2020:

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

June 30, Three months ended

June 30, Six months ended

September 30, Three months ended

September 30, Nine months ended

September 30,

2021 2020 2021 2020

5 unchanged sentences

San Joaquin Basin 13 14 13 14

Ventura Basin — — 1 —

Total 13 14 13 14

11 unchanged sentences

Barrels of oil equivalence does not necessarily result in price equivalence.

Total daily production for the three months ended June 30, 2021, compared to the same period in 2020, decreased by approximately 11 MBoe/d or 10%.

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

Our production-sharing contracts (PSCs), as described below, negatively impacted our oil production in the second quarter of 2021 by approximately five MBoe/d compared to the same period in 2020.

Our total daily production for the three months ended June 30, 2021 decreased by approximately 5% compared to the same period in 2020 after excluding the impact of PSC-type contracts.

For the six months ended June 30, 2021 compared to the same period in 2020, total daily production decreased by approximately 17 MBoe/d or 15%.

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

Production volumes were also negatively impacted by downtime at one of our gas processing plants and our PSC-type contracts.

Our total daily production decreased by 12 MBoe/d or 10% compared to the same period in 2020 after excluding the impact of PSC-type contracts and unscheduled downtime.

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.

Production-Sharing Contracts (PSCs)

8 unchanged sentences

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 June 30, 2021.

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.

3 unchanged sentences

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.

See Statements of Operations Analysis, Results of Oil and Gas Operations below for our operating costs and operating costs, excluding the effects of our PSC-type contracts on a per Boe basis.

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.

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 six months ended June 30, 2021 and 2020:

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 June 30, Three months ended June 30,

Three months ended September 30, Three months ended September 30,

Price Realization Price Realization

1 unchanged sentence

Brent $ 73.23 $ 43.37

Realized price without hedge $ 68.94 100% $ 30.27 91%

Settled hedges (14.84) 0.55

Realized price with hedge $ 54.10 78% $ 30.82 93%

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 hedge $ 68.94 104% $ 30.27 109%

Realized price with hedge $ 54.10 82% $ 30.82 111%

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)

2 unchanged sentences

NYMEX ($/MMBtu) $ 3.71 $ 1.93

Realized price without hedge ($/Mcf) $ 3.04 110% $ 1.65 93%

Settled hedges (0.01) 0.08

Realized price with hedge ($/Mcf) $ 3.03 110% $ 1.73 98%

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%

Successor Predecessor

Six months ended June 30, Six months ended June 30,

Nine months ended September 30, Nine months ended September 30,

Price Realization Price Realization

1 unchanged sentence

Brent $ 67.78 $ 42.53

Realized price without hedge $ 64.89 100% $ 41.02 97%

Settled hedges (10.98) 2.74

Realized price with hedge $ 53.91 83% $ 43.76 104%

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 hedge $ 64.89 105% $ 41.02 111%

Realized price with hedge $ 53.91 87% $ 43.76 118%

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)

2 unchanged sentences

NYMEX ($/MMBtu) $ 3.06 $ 1.92

Realized price without hedge ($/Mcf) $ 3.17 116% $ 1.96 103%

Settled hedges (0.03) 0.09

Realized price with hedge ($/Mcf) $ 3.14 115% $ 2.05 107%

Oil — Brent index and realized prices excluding hedge settlements were higher in the three and six month periods ended June 30, 2021 compared to the same periods in 2020 as oil demand recovered from its COVID-19 driven lows.

Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing mobility restrictions and the delayed effects of pandemic-related production curtailments and reduced capital investments by OPEC members, domestic producers and Russia.

NGLs — Prices for NGLs increased for the three and six month periods ended June 30, 2021 compared to the same periods in 2020.

In 2020, demand declined at the onset of COVID-19 that caused materially lower NGL prices and resulted in production curtailments.

Production curtailments continued into 2021 causing tighter supplies and higher benchmark prices in the face of improving demand.

Natural Gas — Natural gas index and realized prices were higher in the three and six months ended June 30, 2021 compared to the same periods in 2020.

The pandemic caused natural gas demand to decline which prompted producers to, in response, reduce production and investment.

As pandemic-related mobility restrictions have been lifted, production increases have thus far failed to keep pace with prompt demand and seasonal storage requirements.

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.

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.

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 six months ended June 30, 2021 and 2020:

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

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June 30, Three months ended

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2021 2020 2021 2020

Energy operating costs (a)

September 30, Three 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 (b)

Non-energy operating costs $ 14.23 $ 9.81 $ 13.48 $ 10.50

Operating costs (a)

$ 20.28 $ 14.52 $ 19.04 $ 14.85

Operating costs $ 18.48 $ 12.42 $ 18.40 $ 14.99

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

Field general and administrative expenses (b)

$ 0.96 $ 1.34 $ 0.87 $ 1.16

Field general and administrative expenses (d)

Field depreciation, depletion and amortization (c)

$ 5.12 $ 8.03 $ 5.21 $ 8.68

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

Field taxes other than on income (d)

$ 2.67 $ 3.40 $ 3.02 $ 3.10

Field taxes other than on income $ 2.95 $ 2.84 $ 3.21 $ 2.96

(a) Energy operating costs consist of purchases of fuel gas used to generate electricity, purchased electricity and internal costs to produce electricity used in our operations.

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

Purchases of fuel gas to generate steam which is then used in our steamfloods is included in non-energy operating costs.

(c) As described in the Production 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.

Field general and administrative expenses decreased for the three and six months ended June 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.

(e) Field depreciation, depletion and amortization decreased in the three and six months ended June 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.

(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.

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.

Consolidated Results of Operations

The following table presents our consolidated results of operations for the three and six months ended June 30, 2021 and 2020:

Successor Predecessor Successor Predecessor

Three months ended September 30, 2021 vs.

The following table presents our operating revenues for the three months ended September 30, 2021 and 2020:

Successor Predecessor

Three months ended

June 30, Three months ended

June 30, Six months ended

2021 2020 2021 2020

September 30, Three months ended

September 30,

(in millions)

Oil, natural gas and NGL sales $ 549 $ 312

Net derivative (loss) gain from commodity contracts (265) (4) (478) 75

Trading revenue 48 14 146 59

Net (loss) gain from commodity derivatives (125) —

Sales of purchased natural gas 95 50

Electricity sales 65 43

Other revenue 4 4

Operating costs (169) (127) (333) (319)

General and administrative expenses (48) (69) (96) (129)

Depreciation, depletion and amortization (54) (88) (106) (207)

Asset impairments — — (3) (1,736)

Taxes other than on income (37) (38) (77) (79)

Exploration expense (2) (2) (4) (7)

Trading costs (30) (8) (91) (32)

Electricity cost of sales (17) (14) (41) (30)

Transportation costs (14) (8) (26) (21)

Other expenses, net (23) (37) (53) (53)

Reorganization items (2) — (4) —

Interest and debt expense, net (13) (85) (26) (172)

Net gain on early extinguishment of debt — — (2) 5

Gain on asset divestitures — — — —

Other non-operating expenses (2) (47) (1) (61)

Loss before income taxes (107) (247) (196) (1,992)

Income tax — — — —

Net loss (107) (247) (196) (1,992)

Net income attributable to noncontrolling interests (4) (24) (9) (75)

Net loss attributable to common stock $ (111) $ (271) $ (205) $ (2,067)

Three months ended June 30, 2021 vs.

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $478 million for the three months ended June 30, 2021, which is an increase of $233 million compared to $245 million for the same period of 2020.

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:

1 unchanged sentence

(in millions)

Three months ended June 30, 2020 $ 193 $ 26 $ 26 $ 245

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 June 30, 2021 $ 380 $ 53 $ 45 $ 478

Three months ended September 30, 2021 $ 413 $ 67 $ 69 $ 549

See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

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

Payments for settled hedges were $82 million for the three months ended June 30, 2021 compared to proceeds of $5 million for the same period of 2020.

Including the effect of settled hedges, our oil, natural gas and NGL revenue increased by $146 million or 58% compared to the same prior-year period.

Net derivative loss from commodity contracts — Net derivative loss from commodity contracts was $265 million for the three months ended June 30, 2021 compared to a net loss of $4 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.

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

June 30, Three months ended

September 30, Three months ended

September 30,

(in millions)

Non-cash derivative loss, excluding noncontrolling interest $ (183) $ —

Non-cash derivative loss, noncontrolling interest — (9)

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 derivative loss from commodity contracts $ (265) $ (4)

Trading revenue — Trading revenue was $48 million for the three months ended June 30, 2021, an increase of $34 million, or 243% from $14 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 created by a warmer summer in 2021 as compared to 2020.

Our net margin from natural gas trading activities, after deducting the cost of related natural gas purchases, was $18 million for the three months ended June 30, 2021 compared to $6 million for the same period of 2020.

Electricity sales — Electricity sales increased $14 million to $33 million in the second quarter of 2021 compared to $19 million in the same period of 2020.

Net loss from commodity derivatives $ (125) $ —

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.

Volumes sold in the second quarter of 2020 were lower than the second quarter of 2021 due to planned maintenance at the Elk Hills power plant in the first quarter of 2021 which continued in the early part of April 2020.

Operating costs — Operating costs for the three months ended June 30, 2021 were $169 million, which was an increase of $42 million or 33% from $127 million for the same period of 2020.

The increase was primarily attributable to higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells.

Additionally, operating costs increased in 2021 due to higher energy costs and natural gas prices as compared to 2020.

Partially offsetting these increases were lower compensation-related costs from streamlining our operations, which included headcount reductions in late 2020 and early 2021 as well as benefit reductions in the second quarter of 2021.

Our second quarter 2020 results reflect cost savings for reduced work hours and reduced management salaries in response to the industry downturn resulting from the COVID-19 pandemic.

Although higher natural gas and electricity 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 these commodities which we also produce.

General and administrative expenses — Our general and administrative (G&A) expenses were $48 million for the three months ended June 30, 2021, which was a decrease of $21 million from $69 million for the three months ended June 30, 2020.

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,

(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.

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.

Our second quarter 2020 results include cost savings from reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic.

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 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 $34 million to $54 million in the second quarter of 2021 compared to $88 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.

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.

Trading costs — Natural gas purchases related to trading activities were $30 million for the three months ended June 30, 2021, which was an increase of $22 million or 275% from $8 million for the same period in 2020.

The change was predominantly the result of higher activity levels and prices.

Other expenses, net — Other expenses, net was $23 million for the three months ended June 30, 2021, which was a decrease of $14 million from $37 million during the same period of 2020.

The decrease was largely due to a one-time payment of $20 million made in connection with an expiring pipeline delivery contract partially offset by a $3 million property tax refund.

Interest and debt expense, net — Interest and debt expense, net decreased $72 million to $13 million in the second quarter of 2021 compared to $85 million in the same period of 2020 primarily due to a decrease in our overall level of debt following our emergence from bankruptcy.

Additionally, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn during the quarter.

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.

Other non-operating expense — Other non-operating expense decreased $45 million to $2 million for the three months ended June 30, 2021 compared to $47 million in the same period for 2020.

The decrease primarily due to the significant legal, professional and other fees incurred in preparation for our Chapter 11 filing on July 15, 2020.

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 June 30, 2021 is lower than the Predecessor period for the three months ended June 30, 2020.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on the settlement terms of the Ares JV.

Six Months Ended June 30, 2021 vs.

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $910 million for the six months ended June 30, 2021, which is an increase of $235 million compared to $675 million for the same period of 2020.

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.

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,

(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:

1 unchanged sentence

(in millions)

Six months ended June 30, 2020 $ 549 $ 62 $ 64 $ 675

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)

Six months ended June 30, 2021 $ 711 $ 107 $ 92 $ 910

Nine months ended September 30, 2021 $ 1,124 $ 174 $ 161 $ 1,459

See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

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

Payments for settled hedges were $121 million for the six months ended June 30, 2021 compared to proceeds of $103 million, including $63 million of proceeds from derivative contracts sold prior to maturity, in the first quarter of 2020.

Including the effect of settled hedges, our oil, natural gas and NGL revenue increased by $11 million or 1% compared to the same prior-year period.

Net derivative loss from commodity contracts — Net derivative loss from commodity contracts was $478 million for the six months ended June 30, 2021 compared to a net gain of $75 million in the same period of 2020.

Six months ended

June 30, Six months ended

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.

Nine months ended

September 30, Nine months ended

September 30,

(in millions)

Non-cash derivative loss, excluding noncontrolling interest (357) $ (35)

Non-cash derivative gain, noncontrolling interest — 7

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 derivative contracts sold prior to maturity — 63

Net derivative (loss) gain from commodity contracts $ (478) $ 75

Trading revenue — Trading revenue was $146 million for the six months ended June 30, 2021, an increase of $87 million, or 147% from $59 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 created by colder winter temperatures and a warmer summer in 2021 as compared to 2020.

Our net margin from natural gas trading activities, after deducting the cost of related natural gas purchases, was $55 million for the six months ended June 30, 2021 compared to $27 million for the same period of 2020.

Electricity sales — Electricity sales increased $34 million to $66 million in the first half of 2021 compared to $32 million in the same period of 2020.

Electricity sales increased in the first half of 2021 from the prior year period as a result of higher pricing resulting from reduced hydroelectric generation in California as well as increased natural gas prices.

In the first half of 2020, sales volumes were also lower from planned maintenance and an outage at the Elk Hills power plant.

Operating costs — Operating costs for the six months ended June 30, 2021 were $333 million, which was an increase of $14 million or 4% from $319 million for the same period of 2020.

The increase was primarily attributable to higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells.

Additionally, operating costs increased in 2021 due to higher energy costs and natural gas prices as compared to 2020.

These increases were partially offset by lower compensation-related costs from streamlining our operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021 as well as benefit reductions in the second quarter of 2021.

Although higher natural gas and electricity prices increase our operating costs, higher prices have a net positive effect on our operating results due to higher revenue from sales of these commodities which we also produce.

General and administrative expenses — Our general and administrative (G&A) expenses were $96 million for the six months ended June 30, 2021, which was a decrease of $33 million from $129 million for the six months ended June 30, 2020.

The decrease in G&A expenses were 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.

Net proceeds on commodity derivative contracts sold prior to maturity — 63

Net (loss) gain from commodity derivatives $ (603) $ 75

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,

(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.

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.

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 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 $101 million to $106 million in the first half of 2021 compared to $207 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.

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.

Asset impairments — Asset impairment charges for the six months ended June 30, 2021 were $3 million for the impairment of capitalized costs related to projects which were abandoned.

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.

Trading costs — Natural gas purchases related to trading activities were $91 million for the six months ended June 30, 2021, which was an increase of $59 million or 184% from $32 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.

Electricity cost of sales — Electricity cost of sales increased from $30 million in the first half of 2020 to $41 million in the same period of 2021.

The increase was primarily a result of higher pricing on natural gas purchases.

Interest and debt expense, net — Interest and debt expense, net decreased $146 million to $26 million in the first half of 2021 compared to $172 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 in the second quarter.

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.

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.

Other non-operating expense — Other non-operating expense decreased $60 million to $1 million for the six months ended June 30, 2021 compared to $61 million in the same period for 2020.

The higher expense in the first half of 2020 was primarily a result of legal, professional and other fees related to our bankruptcy filing and an abandoned financing transaction.

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 six months ended June 30, 2021 is lower than the Predecessor period for the six months ended June 30, 2020.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report for additional information on the settlement terms of the Ares JV.

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 (used in) operating activities is sensitive to many variables, including changes in commodity prices.

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 June 30, 2021, our operating cash flow increased 194%, or $262 million, to $127 million from $(135) million in the same prior period of 2020.

For the six months ended June 30, 2021, our operating cash flow increased 195%, or $181 million, to $274 million from $93 million in the same period of 2020.

The increase in operating cash flow primarily relates to higher average realized prices with hedge settlements in 2021 compared to the same prior-year period which is primarily due to the economic recovery in 2021 as COVID-19 driven mobility restrictions were lifted and demand increased.

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.

Changes in operating assets and liabilities in the three months ended June 30, 2021 decreased our operating cash flow by $25 million compared to an increase of $17 million in the comparable period of 2020.

Changes in operating assets and liabilities in the six months ended June 30, 2021 decreased our operating cash flow by $25 million compared to an increase of $130 million in the comparable six months of 2020.

These working capital changes were largely a result of higher trade accounts receivable balances as well as higher payables related to derivatives and increased activity.

Cash flows from investing activities — Our net cash used in investing activities increased $28 million, or 187% from $15 million for the three months ended June 30, 2020 to $43 million for the same period in 2021.

Our net cash used in investing activities increased $36 million, or 133% from $27 million for the six months ended June 30, 2020 to $63 million for the same period in 2021.

The table below summarizes net cash used in investing activities for the three and six months ended June 30, 2021 and 2020 (in millions):

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.

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

June 30, 2021 Three Months Ended

June 30, 2020 Six months ended

June 30, 2021 Six Months Ended

June 30, 2020

September 30, 2021 Three Months Ended

September 30, 2020 Nine months ended

September 30, 2021 Nine Months Ended

September 30, 2020

(in millions)

2 unchanged sentences

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 $63 million for the three months ended June 30, 2021 compared to net cash provided by financing activities of $199 million or the same period of 2020.

Our net cash used in financing activities was $88 million for the six months ended June 30, 2021 compared to net cash provided by financing activities of $43 million for the same period of 2020.

Financing activities for the three months ended June 30, 2021 included repurchases of 1.4 million shares of common stock at an aggregate cost of $45 million under our Share Repurchase Program.

Financing activities for the three and six months ended June 30, 2020 primarily included net borrowings under our revolving credit facility in place at that time.

The table below summarizes net cash used by financing activities for the three and six months ended June 30, 2021 and 2020 (in millions):

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

June 30, 2021 Three Months Ended

June 30, 2020 Six months ended

June 30, 2021 Six Months Ended

June 30, 2020

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

Debt repurchases — — — (3)

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) provided by financing activities $ (63) $ 199 $ (88) $ 43

Net cash used in financing activities $ (56) $ (51) $ (144) $ (8)

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 half of 2021 was for capital investment, distributions to a noncontrolling interest holder and repurchases of our common stock.

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.

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 may begin paying income taxes in early 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, the amount and type of our capital spend, cost structure and activity levels.

Potential legislation could also limit tax incentives for fossil fuels.

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):

September 30,

(in millions)

Revolving Credit Facility:

Borrowing capacity (a)

Borrowing capacity 492

Outstanding letters of credit (133)

1 unchanged sentence

Liquidity $ 548

(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.

Amendment to Revolving Credit Facility

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, including paying dividends and repurchasing our common stock;

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

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

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

1 unchanged sentence

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.

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 on October 27, 2020, 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.

Our Revolving Credit Facility also requires us to 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 NGLs from our oil and gas properties for a 48-month period, except that we may purchase puts and floors up to 100% of such production.

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 or six months ended June 30, 2021.

See Part I, Item 1 – Financial Statements, Note 8 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2021.

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 to $225 million.

We have since reduced the full year 2021 capital program to $170 million to $190 million reflecting a reallocation of drilling capital to downhole maintenance activities which provide efficiencies and faster payouts.

The current capital program anticipates that we will maintain a consistent level of investment throughout the remainder of the year.

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

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.

1 unchanged sentence

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 Full Year Estimate Six months ended June 30, 2021

2021 Full Year Estimate Nine months ended September 30, 2021

(in millions)

4 unchanged sentences

Regulatory Update

In April 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.

In May 2021, the Division published the proposed rule to end the issuance of new permits for well stimulation treatments.

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.

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

In August 2021, our Board of Directors authorized an increase to the Share Repurchase Program by $100 million to $250 million through March 31, 2022.

In the second quarter of 2021, we entered into agreements to sell our Ventura basin operations.

We expect to receive cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices.

The consideration includes $82 million of cash to be paid at closing and up to $20 million of potential additional consideration if the buyer does not perform certain abandonment obligations with respect to the divested properties.

The additional consideration is secured by production payments of $20 million over a five-year period.

To the extent the buyer satisfies all of the required abandonment obligations within a five-year period following the close date, none of the $20 million of potential additional consideration will be paid to us.

The amount of the earn-out consideration actually received is not yet certain, but assuming an average oil price of approximately $80 per barrel during the twelve months following closing, would approximate $8 million and would generally be received in quarterly installments.

The closing of the transaction is subject to customary closing considerations, including satisfaction of land and environmental due diligence and third-party consents.

The sale of our Ventura basin operations met the criteria for assets held for sale and is classified as such on our condensed consolidated balance sheet as of June 30, 2021.

The amount reported as assets held for sale primarily consists of property, plant and equipment along with associated asset retirement obligations.

These transactions are expected to close in the second half of 2021.

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.

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 April 2017, we entered into a development joint venture with Macquarie Infrastructure and Real Assets Inc.

(MIRA) to develop certain of our oil and natural gas properties in the San Joaquin basin in exchange for a 90% working interest in the related properties.

In August 2021, we purchased MIRA’s entire working interest share in the conveyed assets for $53 million, before transaction costs.

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.

The acquisition of MIRA's working interest would have added oil production of approximately 2 MBoe/d to our consolidated results for the first half of 2021.

In February 2017, we entered into a development joint venture (JV) with Benefit Street Partners (BSP) to develop certain oil and natural gas assets in exchange for a preferred interest in the BSP JV.

BSP invested $200 million and is entitled to preferred distributions and, if it receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment.

For the first half of 2021, we distributed $31 million to BSP.

We anticipate our remaining distributions to BSP in the second half of 2021 will approximate $20 million.

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.

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

Reserve balances at June 30, 2021 and December 31, 2020 were not material to our condensed consolidated balance sheets as of such dates.

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.

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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:

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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.

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;

• 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;

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• 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;

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• 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;

• our ability to realize the benefits of business strategies and initiatives related to energy transition, including carbon capture and sequestration projects and other renewable energy efforts;

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

• 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.

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis