Item 2. Management’s Discussion and Analysis
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.
We qualified for and adopted fresh start accounting upon emergence from bankruptcy on October 27, 2020, at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of our joint plan of reorganization (the Plan), the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.
Business Environment and Industry Outlook
Commodity Prices
Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.
Global oil prices were higher in the three and 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:
Three months ended
June 30, Six months ended
June 30,
2021 2020 2021 2020
Brent oil ($/Bbl) $ 69.02 $ 33.27 $ 65.06 $ 42.12
WTI oil ($/Bbl) $ 66.07 $ 27.85 $ 61.96 $ 37.01
NYMEX gas ($/MMBtu) $ 2.76 $ 1.77 $ 2.74 $ 1.91
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.
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Production
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:
Successor Predecessor Successor Predecessor
Three months ended
June 30, Three months ended
June 30, Six months ended
June 30, Six months ended
June 30,
2021 2020 2021 2020
Oil (MBbl/d)
San Joaquin Basin 39 41 38 44
Los Angeles Basin 19 27 20 26
Ventura Basin 3 2 2 3
Total 61 70 60 73
NGLs (MBbl/d)
San Joaquin Basin 13 13 12 14
Ventura Basin — — 1 —
Total 13 13 13 14
Natural gas (MMcf/d)
San Joaquin Basin 135 148 135 151
Los Angeles Basin 1 2 1 2
Ventura Basin 5 3 5 4
Sacramento Basin 20 21 20 22
Total 161 174 161 179
Total Net Production (MBoe/d) 101 112 100 117
Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
Total daily production for the three months ended 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.
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Production-Sharing Contracts (PSCs)
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 15% of our net production for the three months ended June 30, 2021.
In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our oil, natural gas and NGL sales revenue, general and administrative expenses and operating costs but has no effect on our net results.
The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. 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.
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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:
Successor Predecessor
Three months ended June 30, Three months ended June 30,
2021 2020
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 69.02 $ 33.27
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%
WTI $ 66.07 $ 27.85
Realized price without hedge $ 68.94 104% $ 30.27 109%
Realized price with hedge $ 54.10 82% $ 30.82 111%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 44.90 65% $ 21.05 63%
Realized price (% of WTI) $ 44.90 68% $ 21.05 76%
Natural gas
NYMEX ($/MMBtu) $ 2.76 $ 1.77
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%
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Successor Predecessor
Six months ended June 30, Six months ended June 30,
2021 2020
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 65.06 $ 42.12
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%
WTI $ 61.96 $ 37.01
Realized price without hedge $ 64.89 105% $ 41.02 111%
Realized price with hedge $ 53.91 87% $ 43.76 118%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 46.75 72% $ 25.18 60%
Realized price (% of WTI) $ 46.75 75% $ 25.18 68%
Natural gas
NYMEX ($/MMBtu) $ 2.74 $ 1.91
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.
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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:
Successor Predecessor Successor Predecessor
Three months ended
June 30, Three months ended
June 30, Six months ended
June 30, Six months ended
June 30,
2021 2020 2021 2020
Energy operating costs (a)
$ 4.70 $ 3.51 $ 4.70 $ 3.61
Gas processing costs 0.66 0.46 $ 0.60 $ 0.57
Non-energy operating costs (b)
13.12 8.45 $ 13.10 $ 10.81
Operating costs $ 18.48 $ 12.42 $ 18.40 $ 14.99
Operating costs, excluding effects of PSC-type contracts (c)
$ 16.75 $ 12.00 $ 16.74 $ 14.33
Field general and administrative expenses (d)
$ 0.77 $ 1.17 $ 0.83 $ 1.08
Field depreciation, depletion and amortization (d)(e)
$ 5.36 $ 7.82 $ 5.25 $ 8.98
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. 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.
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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
June 30, Three months ended
June 30, Six months ended
June 30, Six months ended
June 30,
2021 2020 2021 2020
(in millions)
Oil, natural gas and NGL sales $ 478 $ 245 $ 910 $ 675
Net derivative (loss) gain from commodity contracts (265) (4) (478) 75
Trading revenue 48 14 146 59
Electricity sales 33 19 66 32
Other revenue 10 2 23 8
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. 2020
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. 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 June 30, 2020 $ 193 $ 26 $ 26 $ 245
Changes in realized prices 246 29 22 297
Changes in production (59) (2) (3) (64)
Three months ended June 30, 2021 $ 380 $ 53 $ 45 $ 478
Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
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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.
Three months ended
June 30, Three months ended
June 30,
2021 2020
(in millions)
Non-cash derivative loss, excluding noncontrolling interest $ (183) $ —
Non-cash derivative loss, noncontrolling interest — (9)
Total non-cash changes (183) (9)
Net (payments) proceeds on settled commodity derivatives (82) 5
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. 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 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.
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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. 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. 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. 2020
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. 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)
Six months ended June 30, 2020 $ 549 $ 62 $ 64 $ 675
Changes in realized prices 319 53 39 411
Changes in production (157) (8) (11) (176)
Six months ended June 30, 2021 $ 711 $ 107 $ 92 $ 910
Note: 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.
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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. 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.
Six months ended
June 30, Six months ended
June 30,
2021 2020
(in millions)
Non-cash derivative loss, excluding noncontrolling interest (357) $ (35)
Non-cash derivative gain, noncontrolling interest — 7
Total non-cash changes (357) (28)
Net (payments) proceeds on settled commodity derivatives (121) 40
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. 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. 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.
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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. 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 12 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. 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 $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.
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. 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. 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.
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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):
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
(in millions)
Capital investments $ (50) $ (3) $ (77) $ (33)
Changes in capital investment accruals 8 (9) 13 (28)
Proceeds from divestitures — — 2 41
Other (1) (3) (1) (7)
Net cash used in investing activities $ (43) $ (15) $ (63) $ (27)
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):
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
(in millions)
Debt transactions, net $ (1) $ 223 $ (12) $ 113
Debt repurchases — — — (3)
Distributions to noncontrolling interest holders, net (17) (24) (31) (66)
Repurchases of common stock (45) — (45) —
Other — — — (1)
Net cash (used in) provided by financing activities $ (63) $ 199 $ (88) $ 43
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the first half of 2021 was for capital investment, distributions to a noncontrolling interest holder and repurchases of our common stock.
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 believe we have sufficient sources of cash to meet our obligations for the next twelve months.
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The following table summarizes our liquidity (in millions):
Successor
June 30,
2021
(in millions)
Cash $ 151
Revolving Credit Facility:
Borrowing capacity (a)
492
Outstanding letters of credit (125)
Availability $ 367
Liquidity $ 518
(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; 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 NGLs for a 48-month period.
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.
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.
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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.
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.
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):
Successor
2021 Full Year Estimate Six months ended June 30, 2021
(in millions)
Drilling $90 - $100 $41
Capital workovers 35 - 40 17
Infrastructure, corporate and other 45 - 50 19
Total $170 - $190 $77
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. 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.
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.
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Divestitures
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.
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. 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 BSP JV.
Seasonality
While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a material driver of changes in our quarterly results.
Fixed and Variable Costs
Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. The measures taken to address the industry downturn in the prior year demonstrate that we can significantly reduce our operating costs in response to prevailing market conditions. We further believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs in a safe and responsible manner throughout their lifecycles.
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Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at June 30, 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.
See Part I, Item 1 – Financial Statements, Note 7 Lawsuits, Claims, Commitments and Contingencies for further information.
Significant Accounting and Disclosure Changes
See Part I, Item 1 – Financial Statements, Note 2 Accounting and Disclosure Changes for a discussion of new accounting matters.
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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 and reservoir characteristics
• type curves
• expected synergies from acquisitions and joint ventures
• energy transition initiatives
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. 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 (i) drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) managing energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) protection of health, safety and the environment, (iv) tax credits or other incentives, or (v) transportation, marketing and sale of our products;
• joint ventures and acquisitions and our ability to achieve expected synergies;
• the recoverability of resources and unexpected geologic conditions;
• incorrect estimates of reserves and related future cash flows and the inability to replace reserves;
• changes in business strategy;
• 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
• 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.
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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.
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.