What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-08-06 compared with 2021-05-13 · 284 added, 261 removed, 212 unchanged (72% of the section changed)

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Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

Chapter 11 Proceedings

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases).

On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new equity owners and a significantly improved financial position.

Fresh Start Accounting

We qualified for and adopted fresh start accounting upon emergence from bankruptcy at which point we became a new entity for financial reporting purposes.

We 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 the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date.

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.

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See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

Organization Changes

In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions, making progress towards our lower cost operating model.

We changed our 2021 capital guidance to reallocate investments to downhole maintenance activities, which will result in an increase in estimated 2021 operating costs.

As a result, we expect our sustainable cost savings in general and administrative expense and operating costs to be $80 million in 2021 as compared to 2020 levels.

We believe the steps taken to date have improved our financial condition and streamlined our business.

In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020.

On December 31, 2020, our former President, Chief Executive Officer and director Todd A.

Stevens departed and Mark A.

(Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors.

On March 22, 2021, the Board of Directors appointed Mr.

McFarland as President and Chief Executive Officer on a permanent basis.

On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr.

McFarland as the Chair of our Board of Directors.

McFarland will continue to serve as a director.

Recent Debt Transactions

In January 2021, we completed a private offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes).

The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and our EHP Notes, with the remaining proceeds used to pay down a portion of the outstanding borrowings under our Revolving Credit Facility.

For more information on the terms of Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 5 Debt.

In May 2021, we amended the Revolving Credit Facility to:

• increase our borrowing base from $1.167 billion to $1.2 billion;

• evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million;

• increase our capacity to make certain restricted payments;

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

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

Share Repurchase Program

In May 2021, our Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of our common stock through March 31, 2022.

The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions.

The SRP does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time.

Business Environment and Industry Outlook

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Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.

Global oil prices gradually increased beginning in October 2020 through the first quarter of 2021.

Benchmark prices for Brent crude oil in the first quarter of 2021 increased approximately 35% from the fourth quarter of 2020 demonstrating a strong recovery from the prior year when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) pandemic.

Current pricing has benefited from the gradual re-opening of the economy and the lifting of restrictions related to the COVID-19 pandemic.

Further, members of Organization of Petroleum Exporting Countries (OPEC) and non-OPEC producers have restrained crude oil production attempting to reduce oil supplies built during the worst period of the pandemic.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2021, December 31, 2020 and March 31, 2020:

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:

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March 31, Three months ended

December 31, Three months ended

June 30, Six months ended

2021 2020 2021 2020

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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.

Recent Developments

Certain actions of the new U.S.

administration could impact the oil and gas industry.

Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production.

Such outcomes could materially and adversely affect our business, results of operations and financial condition.

On April 23, 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045.

This marks a reversal from the governor’s previous statements that he lacked the executive authority to ban hydraulic fracturing, and any decision to prohibit the extraction of oil would likely be subject to significant opposition and legal challenge.

Regardless of whether or not such a ban is upheld, we expect little to no impact on future development activities because we are not dependent on well stimulation treatments.

Less than 1% of our proved reserves require well stimulation and our current long-term development plans do not include well stimulation.

We have the largest privately held oil and natural gas mineral acreage position in California, consisting of 2.1 million net mineral acres spanning four of California's major oil and natural gas basins.

We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements.

Approximately 65% of our mineral acreage is held in fee and the remainder is leased.

Of our leased acreage, approximately 50% is held by production and the remainder is subject to lease expiration if initial producing wells are not drilled within a specified period of time.

The primary terms of our leases range from one to ten years.

The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained.

As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells in response to a low commodity price environment while retaining our oil and gas leases which are held by production.

With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities.

We also own or control a network of integrated infrastructure that complements our operations including gas processing plants, oil and gas gathering systems, power plants and other related assets.

Our strategically located infrastructure helps us maximize the value generated from our production.

Beyond our essential role in supplying Californians with oil, natural gas, NGLs and electricity, our 2030 Sustainability Goal for carbon is to design and permit California’s first carbon capture and sequestration system by mid-decade which is expected to reduce carbon emissions associated with our operations and significantly extend the productive life of our Elk Hills field.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets.

Under such contracts we are obligated to fund all capital and operating costs.

We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit.

Our portion of the production represents volumes:

(i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter.

We generate returns through our defined share of production from (ii) and (iii) above.

These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts.

Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs.

However, our net economic benefit is greater when product prices are higher.

These contracts represented approximately 16% of our net production for the three months ended March 31, 2021.

In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs.

We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues.

Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts.

This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our oil, natural gas and NGL sales revenue, general and administrative expenses and operating costs but has no effect on our net results.

Marketing Arrangements

We own a large and geographically diverse portfolio of assets that generate the following revenue streams:

Crude Oil — We sell almost all of our crude oil into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S.

Substantially all of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems.

We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong.

California is heavily reliant on imported sources of energy, with approximately 70% of oil and 90% of natural gas consumed in 2019 imported from outside the state.

Nearly all of the imported oil arrives via supertanker, mostly from foreign locations.

As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices.

We believe that the limited crude transportation infrastructure from other parts of the U.S.

into California will continue to contribute to higher realizations than most other U.S.

oil markets for comparable grades.

Natural Gas — We sell all of our natural gas not used in our operations into the California markets on a daily basis at average monthly index pricing.

Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity in the market and producing areas.

Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada.

As a result, we typically enjoy higher netback pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas.

Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and approximately 11% of our revenue from oil, natural gas and NGL sales are from natural gas.

In addition to selling our produced natural gas, we also purchase natural gas for use in steam generation for our steamfloods and power generation.

The positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to more volumes sold than used.

Conversely, lower natural gas prices lower our operating costs but have a net negative effect on our financial results.

We currently have transportation capacity contracts to transport the majority of our natural gas volumes until September 2023.

Natural Gas Liquid (NGL) — NGL price realizations are related to the supply and demand for the products making up these liquids.

Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock.

In addition, infrastructure constraints and seasonality can magnify price volatility.

Our earnings are also affected by the performance of our complementary natural gas-processing plants.

We process our wet gas to extract NGLs and other natural gas byproducts.

We then deliver dry gas to pipelines and separately sell the NGLs.

The efficiency with which we extract liquids from the wet gas stream affects our operating results.

Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a pipeline delivery contract to transport 6,500 barrels per day of NGLs to market through March 2023.

Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped.

We have thus far met all of our shipping commitments under this contract.

We sell virtually all of our NGLs using index-based pricing.

Our NGLs are generally sold pursuant to contracts that are renewed annually.

Approximately 30% of our NGLs are sold to export markets.

Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces field operating costs and provides a reliable source of power.

We sell the excess electricity generated to a local utility, other third parties and the grid.

The power sold to the utility is subject to an agreement through the end of 2023, which includes a monthly capacity payment plus a variable payment based on the quantity of power purchased each month.

Any excess capacity not sold to other third parties is sold to the wholesale power market.

The prices obtained for excess power impact our earnings but generally by a relatively small amount.

Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows.

Our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred on the Effective Date, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date.

The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.

We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report if our leverage ratio is greater than 2.00:1.00.

If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are required to maintain is reduced from 50% to 33%.

Currently, we may not hedge more than 85% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period.

In the three months ended March 31, 2021, we added hedges on one million barrels of production for the period from April 2021 to March 2022 at a weighted-average Brent price of approximately $61 per barrel.

See Liquidity and Capital Resources below for a current table summarizing our outstanding derivative contracts.

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.

Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2021 and 2020:

Successor Predecessor

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

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2021 2020 2021 2020

San Joaquin Basin 39 41 38 44

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Ventura Basin 3 2 2 3

Total 61 70 60 73

NGLs (MBbl/d)

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Ventura Basin — — 1 —

Total 13 13 13 14

Natural gas (MMcf/d)

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

For the three months ended March 31, 2021 compared to the same period in 2020, total daily production decreased by approximately 22 MBoe/d or 18%.

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

Our average drilling rigs decreased from 7 in the three months ended March 31, 2020 to 1 rig in the three months ended March 31, 2021.

In addition, production was also negatively impacted by 1 MBoe/d in the first quarter of 2021 compared to 2020 due to downtime at one of our gas processing plants.

Our PSC-type contracts negatively impacted our oil production in the first quarter of 2021 by approximately 3 MBoe/d compared to the same period in 2020.

Our total daily production decreased by approximately 15% compared to the same period in 2020 after excluding the impact of PSC-type contracts and unscheduled downtime at one of our natural gas processing plants.

The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three months ended March 31, 2021 and 2020:

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.

Production-Sharing Contracts (PSCs)

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:

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.

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.

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.

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 March 31, Three months ended March 31,

Three months ended June 30, Three months ended June 30,

Price Realization Price Realization

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

Oil — Brent index and realized prices without hedge settlements were higher in the three months ended March 31, 2021 compared to the same prior-year period due to a recovery in oil demand from the severe demand decline caused by COVID-19 in 2020.

Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing restrictions and the significant production curtailments by OPEC members and Russia.

Further, most producers in other nations also curtailed production and significantly reduced their capital investments in response to COVID-19 in 2020, which continued into 2021.

NGLs — Prices for NGLs increased for the three months ended March 31, 2021 compared to the same period in 2020 as supply in 2020 outpaced demand, causing lower NGL prices in the first quarter of 2020.

In the first quarter of 2021, producers continued to curtail production and the tighter supply resulted in higher benchmark prices and price realizations as compared to the same prior year period.

Natural Gas — Our natural gas realized prices were higher in the three months ended March 31, 2021 than the comparable period of 2020 due to increased natural gas demand in the nationwide markets.

This was a significant change from the first quarter of 2020 in which demand decreased as a result of shelter-in-place orders related to COVID-19.

Successor Predecessor

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

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%

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.

Statements of Operations Analysis

We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting.

As a result of the application of fresh start accounting and the implementation of the Plan, our results of operations for the Successor period may not be comparable with that of the Predecessor period.

Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

Results of Oil and Gas Operations

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended March 31, 2021 and 2020:

Successor Predecessor

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

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2021 2020 2021 2020

Energy operating costs (a)

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Non-energy operating costs (b)

13.12 8.45 $ 13.10 $ 10.81

Operating costs $ 18.48 $ 12.42 $ 18.40 $ 14.99

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$ 5.36 $ 7.82 $ 5.25 $ 8.98

Field taxes other than on income (d)

$ 3.46 $ 3.08

(a) Energy operating costs include purchases of fuel gas and electricity used in our operations and internal costs to produce electricity used in our fields.

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.

(c) As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.

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.

(e) Field depreciation, depletion and amortization decreased in the three months ended March 31, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting.

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.

Consolidated Results of Operations

The following table presents our consolidated results of operations and key financial measures for the three months ended March 31, 2021 and 2020:

Successor Predecessor

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

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2021 2020 2021 2020

(in millions)

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

Three months ended March 31, 2021 vs.

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $432 million for the three months ended March 31, 2021, which is an increase of $2 million compared to $430 million for the same period of 2020.

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.

The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table:

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(in millions)

Three months ended March 31, 2020 $ 356 $ 36 $ 38 $ 430

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 March 31, 2021 $ 331 $ 54 $ 47 $ 432

See Production and Prices for index prices, realizations and production volumes for comparative periods.

Three months ended June 30, 2021 $ 380 $ 53 $ 45 $ 478

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 $39 million for the three months ended March 31, 2021 compared to proceeds of $98 million, including $63 million of proceeds from derivative contracts sold prior to maturity, for the same period of 2020.

Including the effect of settled hedges, our oil, natural gas and NGL revenue decreased by $135 million or 26% compared to the same prior-year period.

Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $213 million for the three months ended March 31, 2021 compared to a net gain of $79 million in the same period of 2020.

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

March 31, Three months ended

June 30, Three months ended

(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.

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.

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

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

(in millions)

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

Non-cash derivative gain, noncontrolling interest — 7

3 unchanged sentences

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

Trading revenue – Trading revenue was $98 million for the three months ended March 31, 2021, an increase of $53 million, or 118% from $45 million during the same period of 2020.

The increase was predominantly the result of higher volume and prices related to our natural gas trading activities.

Our net profit from natural gas trading activities, after consideration of trading costs described below, was $37 million for the three months ended March 31, 2021 compared to $21 million for the same period of 2020.

Electricity sales – Electricity sales increased $20 million to $33 million in the first quarter of 2021 compared to $13 million in the same period of 2020.

There were lower electricity sales in the first quarter of 2020 as a result of planned major maintenance at the Elk Hills power plant.

Operating costs — Operating costs for the three months ended March 31, 2021 were $164 million, which was a decrease of $28 million or 15% from $192 million for the same period of 2020.

The decrease was primarily attributable to efficiencies and streamlining of our operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021.

General and administrative expenses — Our general and administrative (G&A) expenses were $48 million for the three months ended March 31, 2021, which was a decrease of $12 million from $60 million for the three months ended March 31, 2020.

The decrease in G&A expenses were attributable to efficiencies and streamlining of our operations, including a decrease of $7 million in employee related expenses as a result of workforce reductions.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $67 million to $52 million in the first quarter of 2021 compared to $119 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting.

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.

Asset impairments – Asset impairment charges for the three months ended March 31, 2021 were $3 million for the impairment of capitalized costs related to projects which were abandoned.

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 $61 million for the three months ended March 31, 2021, which was an increase of $37 million or 154% from $24 million for the same period in 2020.

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.

Other expenses, net – Other expenses, net was $30 million for the three months ended March 31, 2021, which was an increase of $14 million from $16 million during the same period of 2020.

The increase was largely the result of a restructuring charge related to workforce reductions in the three months ended March 31, 2021.

Interest and debt expense, net — Interest and debt expense, net decreased $74 million to $13 million in the first quarter of 2021 compared to $87 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from bankruptcy.

Additionally, in the first quarter of 2021, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn for two months in the period.

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.

Other non-operating expense — Other non-operating expense decreased $13 million to $1 million for the three months ended March 31, 2021 compared to $14 million in the same period for 2020.

The expense in the first quarter of 2020 was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, which were incurred prior to our petition date, and abandoned transactions.

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

1 unchanged sentence

therefore, the allocation of net income to noncontrolling interest

holders in the Successor period for the three months ended March 31, 2021 is lower than the Predecessor period for the three months ended March 31, 2020.

See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information on the settlement terms of the Ares JV.

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

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.

Our operating cash flow decreased 36%, or $81 million, to $147 million for the three months ended March 31, 2021 from $228 million in the same period of 2020.

The net change in operating cash flow includes decreases primarily from:

(i) settlement payments on our derivative contracts in the first quarter of 2021 compared to proceeds received during the first quarter of 2020 and (ii) a large increase in trade accounts receivable resulting from changes in entry and exit prices between the comparative quarters.

These decreases were partially offset by lower (i) operating costs primarily related to workforce reductions, (ii) interest payments on our long-term debt and (iii) payments of variable compensation as a result of changing from an annual payment in the first quarter of 2020 compared to quarterly payments in the first quarter of 2021.

Cash flows from investing activities — Our net cash used in investing activities increased $8 million, or 67% from $12 million for the three months ended March 31, 2020 to $20 million for the same period in 2021.

Cash used in investing activities included $49 million for capital investment in the three months ended March 31, 2020 compared to $22 million in the three months ended March 31, 2021 due to lower activity levels in 2021.

Capital investments were partially offset by $41 million related to royalty interest and non-core asset sales in the first quarter of 2020 as compared to proceeds of $2 million in the first quarter of 2021 for non-core asset sales.

The table below summarizes net cash used in investing activities for the three months ended March 31, 2021 and 2020 (in millions):

Successor Predecessor

Three months ended March 31, 2021 Three months ended March 31, 2020

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.

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)

2 unchanged sentences

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 of $25 million for the three months ended March 31, 2021 included $14 million of distributions to noncontrolling interest holders and a net $11 million of cash used to repay long-term debt.

See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our debt.

Our net cash used in financing activities for the three months ended March 31, 2020 was $156 million and primarily included net repayments of $110 million on our debt obligations and $42 million in net distributions to noncontrolling interest holders.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Notes.

The table below summarizes net cash used by financing activities for the three months ended March 31, 2021 and 2020 (in millions):

Successor Predecessor

Three months ended March 31, 2021 Three months ended March 31, 2020

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)

2 unchanged sentences

Distributions to noncontrolling interest holders, net (17) (24) (31) (66)

Net cash used by financing activities $ (25) $ (156)

Repurchases of common stock (45) — (45) —

Other — — — (1)

Net cash (used in) provided by financing activities $ (63) $ 199 $ (88) $ 43

Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand and available borrowing capacity under our Revolving Credit Facility.

We emerged from bankruptcy with a strong balance sheet and low leverage.

We have substantially revamped our cost structure while maintaining sustainable operations.

We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining.

At current commodity prices and our planned 2021 capital program described below, we expect to generate positive free cash flow, which may be used to (i) increase investments in our drilling program to accelerate value, (ii) pay dividends or buy back stock to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, or (iii) maintain cash on our balance sheet.

We may be required to begin paying income taxes if Brent prices remain above $60 per barrel for a sustained period.

Our tax paying status depends on a number of factors, including but not limited to, potential legislation which could limit tax incentives for fossil fuels, the amount and type of our capital spend, cost structure and activity levels.

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.

Based on the timing of our anticipated cash distributions to Benefit Street Partners (BSP) at current commodity prices, we believe the preferred interest held by BSP in our development joint venture could be automatically redeemed early in the fourth quarter of 2021.

See Part I, Item 1 – Financial Statements, Note 6 Joint Ventures for additional information on our BSP JV.

The following table summarizes our liquidity (in millions):

March 31, April 30,

(in millions)

Unrestricted cash $ 130 $ 123

Revolving Credit Facility:

Borrowing capacity (a)

Letters of credit outstanding (125) (125)

Total availability $ 415 $ 367

Outstanding letters of credit (125)

Availability $ 367

Liquidity $ 518

1 unchanged sentence

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;

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.

Commodity Contracts

Our Revolving Credit Facility requires us to maintain hedges on a notional amount of crude oil production as described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report.

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 months ended March 31, 2021.

At April 30, 2021, we had the following Brent-based crude oil contracts:

2022 January - October 2023

Barrels per day 33,537 36,688 37,037 33,842 27,773 17,758

Weighted-average price per barrel $ 48.73 $ 50.47 $ 60.75 $ 60.00 $ 58.62 $ 58.01

Purchased Puts

Barrels per day 37,872 36,943 35,820 33,842 27,773 17,758

Weighted-average price per barrel $ 40.00 $ 40.18 $ 40.19 $ 40.00 $ 40.00 $ 40.00

Barrels per day 15,149 14,647 14,193 3,416 2,674 —

Weighted-average price per barrel $ 31.41 $ 30.00 $ 32.00 $ 32.00 $ 32.00 $ —

Barrels per day 9,639 10,063 10,922 7,763 6,386 5,919

Weighted-average price per barrel $ 46.35 $ 49.09 $ 51.11 $ 48.17 $ 46.34 $ 47.57

The outcomes of the derivative positions are as follows:

• Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.

• Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.

• Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.

• Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.

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.

2021 Capital Program

1 unchanged sentence

We entered 2021 with an internally funded capital program of $200 million to $225 million.

During the first quarter of 2021, the 2021 capital program was revised to $185 million to $210 million reflecting a reallocation of drilling capital to downhole maintenance, which provide efficiencies and faster payouts.

Our current plan anticipates we will gradually raise quarterly capital investment throughout the year.

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

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.

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 Target Three months ended March 31, 2021

2021 Full Year Estimate Six months ended June 30, 2021

(in millions)

3 unchanged sentences

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.

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.