Business Wire | May 13, 2021 09:00AM EDT

California Resources Corporation Announces First Quarter 2021 Results and $150 Million Share Repurchase Program

May 13, 2021

SANTA CLARITA, Calif.--(BUSINESS WIRE)--May 13, 2021--California Resources Corporation (NYSE: CRC), an independent oil and natural gas exploration and production company, today reported first quarter 2021 operational and financial results.

"CRC delivered on its strategy with strong first quarter results while maintaining solid environmental and safety records," said Mac McFarland, President and Chief Executive Officer. "Given the positive first quarter results, supported by the previously announced capital structure simplification through a senior debt offering and the recent amendment to our Revolving Credit Facility, CRC's Board of Directors authorized a $150 million Share Repurchase Program. This promising step underpins our robust financial fundamentals which are further strengthened by CRC's 2021 projected free cash flow1. As CRC is tracking to the high end of 2021 free cash flow1 guidance, we will look for additional ways to return capital to our shareholders as the year progresses."

First Quarter 2021 Highlights

Financial

* Reported a net loss attributable to common stock of $94 million, or $1.13 per diluted share. Adjusted net income1 was $102 million, or $1.22 per diluted share * Generated adjusted EBITDAX1 of $189 million and free cash flow1 of $120 million * Reaffirmed 2021 free cash flow1 guidance and optimized CRC investment dollars by shifting $15 million from drilling and completions to downhole maintenance projects which provide efficiencies and faster payouts * Closed the quarter with $130 million of cash on hand, an undrawn credit facility and $545 million of liquidity2 * Simplified CRC's capital structure with a senior unsecured $600 million debt offering * Subsequent to quarter end, signed an amendment to its Revolving Credit Facility which provides CRC with additional strategic flexibility with regard to returning capital to shareholders and to future hedging levels, and completed the borrowing base review which set the borrowing base at $1.2 billion * Quarterly operating costs were $164 million and general and administrative (G&A) expenses were $48 million, a reduction of 15% and 20%, respectively, as compared to 1Q20 * Generated net cash provided by operating activities of $147 million with quarterly capital expenditures of $27 million

Operational

* Produced an average of 99,000 net barrels of oil equivalent (BOE) per day, including 60,000 barrels per day of oil * Maintained industry leading HSE standards * Operated one drilling rig in the San Joaquin Basin; operated 30 maintenance rigs; drilled 17 wells (15 online in 1Q21, final two online in 2Q21); and completed 40 capital workovers

2021 Guidance

Given the strength of the first quarter results, CRC reaffirmed previously issued 2021 free cash flow1 guidance of $250 to $350 million and it sees 2021 free cash flow1 trending towards the high end of the stated guidance range. Recognizing capital efficiency improvements and faster payouts on downhole maintenance projects, CRC revised its operating and capital guidance by shifting $15 million of drilling and completions capital to these opportunities. CRC made $27 million of capital investments in the first quarter of 2021. The current capital program anticipates CRC to gradually increase quarterly investment throughout the year if the commodity environment continues to strengthen. If commodity prices decline significantly from current levels, CRC may need to adjust its capital program in response to market conditions. The Company's capital program will be dynamic in response to oil market volatility while focusing on maintaining its oil production, strong liquidity and maximizing its free cash flow.





2021E TOTAL YEAR GUIDANCE Total Year 2021E



Total Production (Mboe/d) 96 - 99

Oil Production (Mbo/d) 60 - 62

Operating Costs ($ millions) $615 - $630

General and administrative expenses ($ millions) $180 - $190

Capital ($ millions) $185 - $210

Free cash flow ($ millions)^1 $250 - $350

Initiating a Share Repurchase Program

In May 2021, CRC's Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of CRC's 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 CRC to repurchase any dollar amount or number of shares and CRC's Board of Directors may modify, suspend, or discontinue authorization of the program at any time. The Share Repurchase Program expires on March 31, 2022.

Sustainability Update

CRC remains dedicated to environmental stewardship and will continue to deliver on its 2030 Sustainability Goals. Given significant progress on CRC's Water and Methane goals, management and the Board are reviewing the current ESG initiatives to enhance them with a strengthened decarbonization strategy. This review will focus particularly on actionable energy transition opportunities including carbon capture, utilization and storage (CCUS), solar power and other renewable projects. The Company expects to provide additional details about this approach next quarter.

Underscoring CRC's commitment to safe and responsible production, the Company's ESG performance and progress on its 2030 Sustainability Goals, which align with California's climate goals toward carbon neutrality in accordance with the Paris Climate Accord, are directly tied to the performance-based compensation of its executives, senior managers and employees. The Board, through its Operations and Sustainability Committee, will continue to highlight, monitor and provide guidance to CRC's efforts to serve as a responsible steward of California's natural resources, safeguard people and the environment, and advance California's long-term goals.

Fresh Start Accounting and Predecessor and Successor Periods

Upon emergence from Chapter 11 bankruptcy proceedings on October 27, 2020, CRC adopted and applied fresh start accounting 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 of reorganization, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. 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.

First Quarter 2021 Results

Successor Predecessor

1st 1st Quarter Quarter

($ and shares in millions, except per share 2021 2020amounts)



Statements of Operations:

Revenues

Total revenues 363 573



Costs and Other

Total costs and other 436 2,222

Operating Loss (73) (1,649)

Net Loss Attributable to Common Stock $ (94) $ (1,796)



Net loss attributable to common stock per share - $ (1.13) $ (36.43) basic and diluted

Adjusted net income (loss) $ 102 $ (8)

Adjusted net income (loss) per share - basic and $ 1.22 $ (0.16) diluted

Weighted-average common shares outstanding - basic 83.3 49.3 and diluted

Adjusted EBITDAX $ 189 $ 251

Successor

Predecessor

1st Quarter

1st Quarter

($ in millions)

2021

2020

Cash Flow Data:

Net cash provided by operating activities

$

147

$

228

Net cash used by investing activities

$

(20)

$

(12)

Net cash used by financing activities

$

(25)

$

(156)

Review of Operating and Financial Results

Total daily net production volumes decreased 18% from 121,000 BOE per day for the first quarter of 2020 to 99,000 BOE per day for the first quarter of 2021. The decrease from the same period in 2020 was primarily due to limited drilling activity and capital investment during the prior twelve months. Production was also negatively impacted by approximately 1,000 BOE per day in the first quarter of 2021 due to downtime at one of CRC's gas processing plants. Production sharing type contracts (PSC-type) at CRC's Long Beach assets negatively impacted oil production by approximately 2,600 BOE per day in the first quarter of 2021 compared to the same prior-year period. CRC's 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 its gas processing plants. See Attachment 3 for further information on production.

Realized oil prices, including the effect of settled hedges, decreased by $1.77 per barrel from $55.50 per barrel in the first quarter of 2020 to $53.73 per barrel in the first quarter of 2021. Realized oil prices were lower in the first quarter of 2021 compared to the same prior-year period primarily due to settlement payments on commodity contracts, compared to receipts from commodity contracts in the first quarter of 2020, despite an increase in benchmark prices between comparative periods. See Attachment 4 for further information on prices.

Adjusted EBITDAX1 for the first quarter of 2021 was $189 million and net cash provided by operating activities was $147 million. Internally funded capital invested during the first quarter of 2021 was $27 million. Free cash flow1 was $120 million. CRC's adjusted EBITDAX1 is not reduced by the one-time restructuring charge of $14 million related to its workforce reductions during the three months ended March 31, 2021.

Successor Predecessor

1st 1st Quarter Quarter

($ in millions) 2021 2020

Cash Flow Data:

Net cash provided by operating activities $ 147 $ 228

Net cash used by investing activities $ (20) $ (12)

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

Review of Operating and Financial Results

Total daily net production volumes decreased 18% from 121,000 BOE per day for the first quarter of 2020 to 99,000 BOE per day for the first quarter of 2021. The decrease from the same period in 2020 was primarily due to limited drilling activity and capital investment during the prior twelve months. Production was also negatively impacted by approximately 1,000 BOE per day in the first quarter of 2021 due to downtime at one of CRC's gas processing plants. Production sharing type contracts (PSC-type) at CRC's Long Beach assets negatively impacted oil production by approximately 2,600 BOE per day in the first quarter of 2021 compared to the same prior-year period. CRC's 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 its gas processing plants. See Attachment 3 for further information on production.

Realized oil prices, including the effect of settled hedges, decreased by $1.77 per barrel from $55.50 per barrel in the first quarter of 2020 to $53.73 per barrel in the first quarter of 2021. Realized oil prices were lower in the first quarter of 2021 compared to the same prior-year period primarily due to settlement payments on commodity contracts, compared to receipts from commodity contracts in the first quarter of 2020, despite an increase in benchmark prices between comparative periods. See Attachment 4 for further information on prices.

Adjusted EBITDAX1 for the first quarter of 2021 was $189 million and net cash provided by operating activities was $147 million. Internally funded capital invested during the first quarter of 2021 was $27 million. Free cash flow1 was $120 million. CRC's adjusted EBITDAX1 is not reduced by the one-time restructuring charge of $14 million related to its workforce reductions during the three months ended March 31, 2021.

FREE CASH FLOW



Management uses free cash flow, which is defined by us as net cash provided byoperating activities less capital investments, as a measure of liquidity. Thefollowing table presents a reconciliation of our net cash provided by operatingactivities to free cash flow. We have excluded one-time costs for bankruptcyrelated fees during 2021 and 2020 as a supplemental measure of our free cashflow.



Successor Predecessor

1st Quarter 1st Quarter

($ millions) 2021 2020



Net cash provided by operating activities $ 147 $ 228

Capital investments (27 ) (30 )

Free cash flow 120 198

One-time bankruptcy related fees 2 5

Free cash flow, after special items $ 122 $ 203

Operating costs for the first quarter of 2021 were $164 million, compared to $192 million for the first quarter of 2020. The decrease was primarily attributable to efficiencies and streamlining of CRC's operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021. Operating costs per BOE are presented below:

OPERATING COSTS PER BOE



The reporting of our PSC- type contracts creates a difference between reportedoperating costs, which are for the full field, and reported volumes, which areonly our net share, inflating the per barrel operating costs. The followingtable presents operating costs after adjusting for the excess costsattributable to PSC-type contracts.



Successor Predecessor

1st Quarter 1st Quarter

($ per Boe) 2021 2020

Energy operating costs ^(a) $ 4.70 $ 3.71

Gas processing costs 0.53 0.67

Non-energy operating costs ^(b) 13.10 13.00

Operating costs $ 18.33 $ 17.38

Excess costs attributable to PSC-type contracts (1.61 ) (0.90 )

Operating costs, excluding effects of PSC-type $ 16.72 $ 16.48 contracts



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

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

G&A expenses were $48 million for the first quarter of 2021, compared to $60 million in the same prior-year period. The decrease in G&A expenses resulted from efficiencies and streamlining of CRC's operations, including a $7 million decrease in employee related expenses as a result of workforce reductions. We expect CRC's quarterly G&A expenses to modestly trend down throughout the year from current levels.

CRC reported taxes other than on income of $40 million for the first quarter of 2021, compared to $41 million for the same prior-year period. Exploration expense was $2 million for the first quarter of 2021 and $5 million in the first quarter of 2020.

Balance Sheet and Liquidity Update

In January 2021, CRC further simplified its balance sheet by completing an offering of $600 million in aggregate principal amount of its 7.125% senior unsecured notes due 2026. The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full CRC's Second Lien Term Loan and EHP Notes. The remaining proceeds were used to pay down substantially all of CRC's then outstanding Revolving Credit Facility.

CRC's aggregate commitment of $540 million as of March 31, 2021 was automatically reduced to $492 million in April 2021 pursuant to the terms of CRC's Revolving Credit Facility. The borrowing base for the Revolving Credit Facility is redetermined around April and October of each year and was most recently set at $1.2 billion in May 2021. The amount CRC is able to borrow under the Revolving Credit Facility is limited to the amount of the commitment described above.

In May 2021, CRC amended its Revolving Credit Facility to provide further strategic flexibility with respect to CRC's minimum and maximum hedging restrictions and to increase CRC's capacity to make certain restricted payments, including paying dividends on its common stock and repurchasing its common stock.

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

Operational Update

During the first quarter of 2021, CRC operated one drilling rig in the San Joaquin Basin, drilled 17 net wells, 15 of which were brought online, and completed 40 capital workovers. Subsequent to the end of the first quarter, CRC added a second drilling rig and increased its maintenance rigs to 38. The San Joaquin basin produced 73,000 net BOE per day. The Los Angeles basin produced 20,000 net BOE per day, the Ventura basin produced 3,000 net BOE per day and the Sacramento basin produced 3,000 net BOE per day.

Organization Changes

In connection with CRC's emergence from bankruptcy, its Board of Directors was reconstituted in October 2020. On December 31, 2020, CRC's 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 CRC's 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 CRC's Board of Directors. Mr. McFarland will continue to serve as a director.

On April 30, 2021, Noelle M. Repetti was appointed Principal Accounting Officer. Mrs. Repetti joined CRC in 2014 as Vice President - Tax, and she assumed additional duties and was appointed Vice President and Controller in August 2017. On May 1, 2021, Jay Bys was appointed Chief Commercial Officer responsible for CRC's marketing and trading operations. Mr. Bys has nearly 30 years of experience across various segments of the energy industry in senior management roles. He will oversee the integration of CRC's renewable energy efforts.

Conference Call Details

To participate in the conference call scheduled for later today at 11:00 a.m. Eastern Time, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10153648/e58af1b180. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.

1 See Attachment 2 for the non-GAAP financial measures of adjusted EBITDAX, operating costs per BOE (excluding effects of PSC-type contracts), adjusted net income (loss) and free cash flow, including reconciliations to their most directly comparable GAAP measure, where applicable. 2 Calculated as $130 million of cash plus $540 million of capacity on CRC's Revolving Credit Facility less $125 million in letters of credit.

About California Resources Corporation

California Resources Corporation (CRC) is an independent oil and natural gas exploration and production company, applying complementary and integrated infrastructure to gather, process and market its production. Using advanced technology, CRC focuses on safely and responsibly supplying affordable energy.

Forward-Looking Statements

The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect CRC's expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding CRC's expectations as to its future:

* financial position, liquidity, cash flows and results of operations * business prospects * transactions and projects * operating costs and general and administrative expenses * operations and operational results including production, hedging and capital investment * budgets and maintenance capital requirements * reserves * type curves * expected synergies from acquisitions and joint ventures

Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While CRC believes assumptions or bases underlying its expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. CRC also believes third-party statements it cites 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:

* CRC's ability to execute its 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 CRC's recent emergence from bankruptcy on its business and relationships * debt limitations on CRC's financial flexibility * insufficient cash flow to fund planned investments, interest payments on CRC's debt, debt repurchases or changes to CRC's 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 * CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations * legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases (GHGs) or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of CRC products * joint ventures and acquisitions and CRC's 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 CRC's 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 * factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K available at www.crc.com.

Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Attachment 1

SUMMARY OF RESULTS



Combined Successor Predecessor (Non- Successor Predecessor GAAP)

1st Quarter 1st Quarter 4th Quarter 4th Quarter 4th Quarter

($ and shares inmillions, except 2021 2020 2020 2020 2020per shareamounts)



Statements of Operations:

Revenues

Oil, natural gas $ 432 $ 430 $ 342 $ 237 $ 105 and NGL sales

Net derivative(loss) gain from (213 ) 79 (125 ) (141 ) 16 commoditycontracts

Other revenue

Trading revenue 98 45 53 38 15

Electricity 33 13 26 15 11 sales

Other 13 6 5 3 2

Total revenues 363 573 301 152 149



Costs and Other

Operating costs 164 192 165 114 51

General andadministrative 48 60 59 40 19 expenses

Depreciation,depletion and 52 119 66 34 32 amortization

Asset 3 1,736 - - - impairments

Taxes other than 40 41 23 10 13 on income

Exploration 2 5 2 1 1 expense

Other expenses, net

Trading costs 61 24 35 24 11

Electricity cost 24 16 16 10 6 of sales

Transportation 12 13 12 8 4 costs

Other 30 16 31 17 14

Total costs and 436 2,222 409 258 151 other



Operating Loss (73 ) (1,649 ) (108 ) (106 ) (2 )



Non-Operating (Loss) Income

Reorganization (2 ) - 3,991 (3 ) 3,994 items, net

Interest anddebt expense, (13 ) (87 ) (17 ) (11 ) (6 ) net

Net (loss) gainon (2 ) 5 - - - extinguishmentof debt

Gains on asset 2 - - - - divestitures

Othernon-operating (1 ) (14 ) 4 (5 ) 9 expenses



(Loss) IncomeBefore Income (89 ) (1,745 ) 3,870 (125 ) 3,995 Taxes

Income tax - - - - - provision

Net (Loss) (89 ) (1,745 ) 3,870 (125 ) 3,995 Income

Net (income)lossattributable to (5 ) (51 ) (8 ) 2 (10 ) noncontrollinginterests

Net (Loss)Income $ (94 ) $ (1,796 ) $ 3,862 $ (123 ) $ 3,985 Attributable toCommon Stock



Net (loss)incomeattributable to $ (1.13 ) $ (36.43 ) $ - $ (1.48 ) $ 80.20 common stock pershare - basicand diluted



Adjusted net $ 102 $ (8 ) $ 8 $ 28 $ (20 ) income (loss)

Adjusted netincome (loss)per share - $ 1.22 $ (0.16 ) $ - $ 0.34 $ (0.40 ) basic anddiluted



Weighted-averagecommon sharesoutstanding - 83.3 49.3 - 83.3 49.5 basic anddiluted



Adjusted EBITDAX $ 189 $ 251 $ 116 $ 83 $ 33

Effective tax 0 0 0 0 0 rate % % % % %

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Qtr.

1st Qtr.

4th Qtr.

4th Qtr.

4th Qtr.

($ in millions)

2021

2020

2020

2020

2020

Cash Flow Data:

Net cash provided (used) by operating activities

$

147

$

228

$

(35

)

$

(12

)

$

(23

)

Net cash used by investing activities

$

(20

)

$

(12

)

$

(9

)

$

(7

)

$

(2

)

Net cash (used) provided by financing activities

$

(25

)

$

(156

)

$

(50

)

$

(156

)

$

106



Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st Qtr. 1st Qtr. 4th Qtr. 4th Qtr. 4th Qtr.

($ in 2021 2020 2020 2020 2020millions)

Cash Flow Data:

Net cashprovided(used) by $ 147 $ 228 $ (35 ) $ (12 ) $ (23 ) operatingactivities

Net cashused by $ (20 ) $ (12 ) $ (9 ) $ (7 ) $ (2 ) investingactivities

Net cash(used)provided $ (25 ) $ (156 ) $ (50 ) $ (156 ) $ 106 byfinancingactivities

March 31,

December 31,

($ and shares in millions)

2021

2020

Selected Balance Sheet Data:

Total current assets

$

461

$

329

Property, plant and equipment, net

$

2,625

$

2,655

Total current liabilities

$

622

$

473

Long-term debt, net

$

588

$

597

Other long-term liabilities

$

889

$

822

Stockholder's Equity

$

1,081

$

1,182

Outstanding shares

83.3

83.3

March 31, December 31,

($ and shares in millions) 2021 2020



Selected Balance Sheet Data:

Total current assets $ 461 $ 329

Property, plant and equipment, net $ 2,625 $ 2,655

Total current liabilities $ 622 $ 473

Long-term debt, net $ 588 $ 597

Other long-term liabilities $ 889 $ 822

Stockholder's Equity $ 1,081 $ 1,182



Outstanding shares 83.3 83.3

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Qtr.

1st Qtr

4th Qtr.

4th Qtr.

4th Qtr.

($ millions)

2021

2020

2020

2020

2020

Non-cash derivative (loss) gain - excluding noncontrolling interest

$

(174

)

$

(35

)

$

(125

)

$

(138

)

$

13

Non-cash derivative gain (loss) - noncontrolling interest

-

16

(2

)

(2

)

-

Total non-cash changes

(174

)

(19

)

(127

)

(140

)

13

Net (payments) proceeds on settled commodity derivatives

(39

)

35

2

(1

)

3

Net proceeds on sale of commodity derivatives

-

63

-

-

-

Net derivative (loss) gain from commodity contracts

$

(213

)

$

79

$

(125

)

$

(141

)

$

16

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS





Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st Qtr. 1st Qtr 4th Qtr. 4th Qtr. 4th Qtr.

($ millions) 2021 2020 2020 2020 2020



Non-cashderivative(loss) gain - $ (174 ) $ (35 ) $ (125 ) $ (138 ) $ 13 excludingnoncontrollinginterest

Non-cashderivativegain (loss) - - 16 (2 ) (2 ) - noncontrollinginterest

Total non-cash (174 ) (19 ) (127 ) (140 ) 13 changes

Net (payments)proceeds onsettled (39 ) 35 2 (1 ) 3 commodityderivatives

Net proceedson sale of - 63 - - - commodityderivatives

Net derivative(loss) gain $ (213 ) $ 79 $ (125 ) $ (141 ) $ 16 from commoditycontracts

CAPITAL INVESTMENTS

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Qtr.

1st Qtr

4th Qtr.

4th Qtr.

4th Qtr.

($ millions)

2021

2020

2020

2020

2020

Internally funded capital

$

27

$

30

$

10

$

7

$

3

Capital investments not included on our financial statements:

MIRA funded capital

-

2

-

-

-

Alpine funded capital

-

89

(1

)

(1

)

-

Total capital program

$

27

$

121

$

9

$

6

$

3

CAPITAL INVESTMENTS





Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st Qtr. 1st Qtr 4th Qtr. 4th Qtr. 4th Qtr.

($ 2021 2020 2020 2020 2020millions)



Internallyfunded $ 27 $ 30 $ 10 $ 7 $ 3 capital

Capitalinvestmentsnotincluded on ourfinancialstatements:

MIRA funded - 2 - - - capital

Alpinefunded - 89 (1 ) (1 ) - capital

Totalcapital $ 27 $ 121 $ 9 $ 6 $ 3 program

Attachment 2

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

To supplement the presentation of its financial results prepared in accordance with U.S generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess our financial condition, results of operations and cash flows. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, adjusted EBITDAX margin, discretionary cash flow. free cash flow and operating costs per BOE, among others. These measures are also widely used by the industry, the investment community and our lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the effect of acquisition and development costs of our assets. Management believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of the non-GAAP measures reported in this press release, including reconciliations to their most directly comparable GAAP measure where applicable.

Attachment 2

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS



To supplement the presentation of its financial results prepared inaccordance with U.S generally accepted accounting principles (GAAP),management uses certain non-GAAP measures to assess our financial condition,results of operations and cash flows. The non-GAAP measures include adjustednet income (loss), adjusted EBITDAX, adjusted EBITDAX margin, discretionarycash flow. free cash flow and operating costs per BOE, among others. Thesemeasures are also widely used by the industry, the investment community andour lenders. Although these are non-GAAP measures, the amounts included inthe calculations were computed in accordance with GAAP. Certain itemsexcluded from these non-GAAP measures are significant components inunderstanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the effect of acquisition anddevelopment costs of our assets. Management believes that the non-GAAPmeasures presented, when viewed in combination with its financial andoperating results prepared in accordance with GAAP, provide a more completeunderstanding of the factors and trends affecting the Company's performance.The non-GAAP measures presented herein may not be comparable to othersimilarly titled measures of other companies. Below are additionaldisclosures regarding each of the non-GAAP measures reported in this pressrelease, including reconciliations to their most directly comparable GAAPmeasure where applicable.

ADJUSTED NET INCOME (LOSS)

Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. We define adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing our financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income (loss) and net income (loss) attributable to common stock per share to the non-GAAP financial measure of adjusted net income (loss) and adjusted net income (loss) per share.

Successor

Predecessor

Combined (Non- GAAP)

Successor

Predecessor

1st Quarter

1st Quarter

4th Quarter

4th Quarter

4th Quarter

($ millions, except per share amounts)

2021

2020

2020

2020

2020

Net (loss) income

$

(89

)

$

(1,745

)

$

3,870

$

(125

)

$

3,995

Net income attributable to noncontrolling interests

(5

)

(51

)

(8

)

2

(10

)

Net (loss) income attributable to common stock

(94

)

(1,796

)

3,862

(123

)

3,985

Unusual, infrequent and other items:

Non-cash derivative loss from commodities, excluding noncontrolling interest

174

35

125

138

(13

)

Asset impairments

3

1,736

-

-

-

Reorganization items, net

2

-

(3,991

)

3

(3,994

)

Severance and termination costs

14

-

5

5

-

Net loss (gain) on extinguishment of debt

2

(5

)

-

-

-

Legal and professional fees related to our reorganization

-

5

-

-

-

Power plant maintenance

-

7

-

-

-

Gains on asset divestitures

(2

)

-

-

Rig termination expenses

1

-

2

1

1

Other, net

2

10

5

4

1

Total unusual, infrequent and other items

196

1,788

(3,854

)

151

(4,005

)

Adjusted net income (loss) attributable to common stock

$

102

$

(8

)

$

8

$

28

$

(20

)

Net (loss) income attributable to common stock per share - diluted

$

(1.13

)

$

(36.43

)

$

-

$

(1.48

)

$

80.20

Adjusted net income (loss) per share - diluted

$

1.22

$

(0.16

)

$

-

$

0.34

$

(0.40

)

ADJUSTED NET INCOME (LOSS)



Adjusted net income (loss) and adjusted net income (loss) per share arenon-GAAP measures. We define adjusted net income as net income excluding theeffects of significant transactions and events that affect earnings but varywidely and unpredictably in nature, timing and amount. These events may recur,even across successive reporting periods. Management believes these non-GAAPmeasures provide useful information to the industry and the investmentcommunity interested in comparing our financial performance between periods.Reported earnings are considered representative of management's performanceover the long term. Adjusted net income (loss) is not considered to be analternative to net income (loss) reported in accordance with GAAP. Thefollowing table presents a reconciliation of the GAAP financial measure of netincome (loss) and net income (loss) attributable to common stock per share tothe non-GAAP financial measure of adjusted net income (loss) and adjusted netincome (loss) per share.



Combined Successor Predecessor (Non- Successor Predecessor GAAP)

1st Quarter 1st Quarter 4th Quarter 4th Quarter 4th Quarter

($ millions,except per 2021 2020 2020 2020 2020share amounts)

Net (loss) $ (89 ) $ (1,745 ) $ 3,870 $ (125 ) $ 3,995 income

Net incomeattributableto (5 ) (51 ) (8 ) 2 (10 ) noncontrollinginterests

Net (loss)incomeattributable (94 ) (1,796 ) 3,862 (123 ) 3,985 to commonstock

Unusual,infrequent and other items:

Non-cashderivativeloss fromcommodities, 174 35 125 138 (13 ) excludingnoncontrollinginterest

Asset 3 1,736 - - - impairments

Reorganization 2 - (3,991 ) 3 (3,994 ) items, net

Severance andtermination 14 - 5 5 - costs

Net loss(gain) on 2 (5 ) - - - extinguishmentof debt

Legal andprofessionalfees related - 5 - - - to ourreorganization

Power plant - 7 - - - maintenance

Gains on asset (2 ) - - divestitures

Rigtermination 1 - 2 1 1 expenses

Other, net 2 10 5 4 1

Total unusual,infrequent and 196 1,788 (3,854 ) 151 (4,005 ) other items



Adjusted netincome (loss)attributable $ 102 $ (8 ) $ 8 $ 28 $ (20 ) to commonstock



Net (loss)incomeattributableto common $ (1.13 ) $ (36.43 ) $ - $ (1.48 ) $ 80.20 stock pershare -diluted

Adjusted netincome (loss) $ 1.22 $ (0.16 ) $ - $ 0.34 $ (0.40 ) per share -diluted

FREE CASH FLOW

Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We have excluded one-time costs for bankruptcy related fees during 2021 and 2020 as a supplemental measure of our free cash flow.

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Quarter

1st Quarter

4th Quarter

4th Quarter

4th Quarter

($ millions)

2021

2020

2020

2020

2020

Net cash provided by operating activities

$

147

$

228

$

(35

)

$

(12

)

$

(23

)

Capital investments

(27

)

(30

)

(10

)

(7

)

(3

)

Free cash flow

120

198

(45

)

(19

)

(26

)

One-time bankruptcy related fees

2

5

39

(4

)

43

Free cash flow, after special items

$

122

$

203

$

(6

)

$

(23

)

$

17

FY 2021E

($ millions)

Low

High

Net cash provided by operating activities

$

435

$

560

Capital investments

(185

)

(210

)

Free cash flow

$

250

$

350

FREE CASH FLOW



Management uses free cash flow, which is defined by us as net cash provided byoperating activities less capital investments, as a measure of liquidity. Thefollowing table presents a reconciliation of our net cash provided by operatingactivities to free cash flow. We have excluded one-time costs for bankruptcyrelated fees during 2021 and 2020 as a supplemental measure of our free cashflow.



Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st 1st Quarter 4th Quarter 4th 4th Quarter Quarter Quarter

($ 2021 2020 2020 2020 2020millions)



Net cashprovided by $ 147 $ 228 $ (35 ) $ (12 ) $ (23 ) operatingactivities

Capital (27 ) (30 ) (10 ) (7 ) (3 ) investments

Free cash 120 198 (45 ) (19 ) (26 ) flow

One-timebankruptcy 2 5 39 (4 ) 43 relatedfees

Free cashflow, after $ 122 $ 203 $ (6 ) $ (23 ) $ 17 specialitems



FY 2021E

($ Low Highmillions)

Net cashprovided by $ 435 $ 560 operatingactivities

Capital (185 ) (210 ) investments

Free cash $ 250 $ 350 flow

ADJUSTED EBITDAX

We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as depreciation, depletion and amortization of our assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of our financial covenants under our Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Quarter

1st Quarter

4th Quarter

4th Quarter

4th Quarter

($ millions, except per BOE amounts)

2021

2020

2020

2020

2020

Net (loss) income

$

(89

)

$

(1,745

)

$

3,870

$

(125

)

$

3,995

Interest and debt expense, net

13

87

17

11

6

Depreciation, depletion and amortization

52

119

66

34

32

Exploration expense

2

5

2

1

1

Unusual, infrequent and other items (a)

196

1,788

(3,854

)

151

(4,005

)

Non-cash items

Accretion expense

13

10

11

8

3

Stock-settled compensation

1

2

1

-

1

Post-retirement medical and pension

1

1

1

1

-

Other non-cash items

-

(16

)

2

2

-

Adjusted EBITDAX

$

189

$

251

$

116

$

83

$

33

Net cash provided by operating activities

$

147

$

228

$

(35

)

$

(12

)

$

(23

)

Cash interest

3

49

15

8

7

Exploration expenditures

2

5

2

1

1

Working capital changes

37

(31

)

134

86

48

Adjusted EBITDAX

$

189

$

251

$

116

$

83

$

33

Adjusted EBITDAX per Boe

$

21.12

$

22.72

$

12.25

$

13.24

$

10.30

(a) See Adjusted Net Income (Loss) reconciliation.

DISCRETIONARY CASH FLOW

We define discretionary cash flow as the cash available after distributions to noncontrolling interest holders and cash interest, excluding the effect of working capital changes but before our internal capital investment. Management uses discretionary cash flow as a measure of the availability of cash to reduce debt or fund investments.

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Quarter

1st Quarter

4th Quarter

4th Quarter

4th Quarter

($ millions)

2021

2020

2020

2020

2020

Adjusted EBITDAX

$

189

$

251

$

116

$

83

$

33

Cash interest

(3

)

(49

)

(15

)

(8

)

(7

)

Distributions paid to noncontrolling interest holders:

BSP

(14

)

(24

)

(30

)

(30

)

-

Ares

-

(20

)

(9

)

-

(9

)

Asset retirement obligations and idle well testing

(12

)

(4

)

(9

)

(6

)

(3

)

Discretionary cash flow

$

160

$

154

$

53

$

39

$

14

ADJUSTED EBITDAX



We define Adjusted EBITDAX as earnings before interest expense; income taxes;depreciation, depletion and amortization; exploration expense; other unusual,infrequent and out-of-period items; and other non-cash items. We believe thismeasure provides useful information in assessing our financial condition,results of operations and cash flows and is widely used by the industry, theinvestment community and our lenders. Although this is a non-GAAP measure, theamounts included in the calculation were computed in accordance with GAAP.Certain items excluded from this non-GAAP measure are significant components inunderstanding and assessing our financial performance, such as our cost ofcapital and tax structure, as well as depreciation, depletion and amortizationof our assets. This measure should be read in conjunction with the informationcontained in our financial statements prepared in accordance with GAAP. Aversion of Adjusted EBITDAX is a material component of certain of our financialcovenants under our Revolving Credit Facility and is provided in addition to,and not as an alternative for, income and liquidity measures calculated inaccordance with GAAP.



Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st Quarter 1st Quarter 4th Quarter 4th Quarter 4th Quarter

($ millions, except 2021 2020 2020 2020 2020per BOE amounts)

Net (loss) income $ (89 ) $ (1,745 ) $ 3,870 $ (125 ) $ 3,995

Interest and debt 13 87 17 11 6 expense, net

Depreciation,depletion and 52 119 66 34 32 amortization

Exploration expense 2 5 2 1 1

Unusual, infrequent 196 1,788 (3,854 ) 151 (4,005 ) and other items ^(a)

Non-cash items

Accretion expense 13 10 11 8 3

Stock-settled 1 2 1 - 1 compensation

Post-retirement 1 1 1 1 - medical and pension

Other non-cash items - (16 ) 2 2 -

Adjusted EBITDAX $ 189 $ 251 $ 116 $ 83 $ 33



Net cash provided by $ 147 $ 228 $ (35 ) $ (12 ) $ (23 ) operating activities

Cash interest 3 49 15 8 7

Exploration 2 5 2 1 1 expenditures

Working capital 37 (31 ) 134 86 48 changes

Adjusted EBITDAX $ 189 $ 251 $ 116 $ 83 $ 33



Adjusted EBITDAX per $ 21.12 $ 22.72 $ 12.25 $ 13.24 $ 10.30 Boe



(a) See Adjusted NetIncome (Loss) reconciliation.





DISCRETIONARY CASH FLOW



We define discretionary cash flow as the cash available after distributions tononcontrolling interest holders and cash interest, excluding the effect ofworking capital changes but before our internal capital investment. Managementuses discretionary cash flow as a measure of the availability of cash to reducedebt or fund investments.



Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st Quarter 1st Quarter 4th Quarter 4th Quarter 4th Quarter

($ millions) 2021 2020 2020 2020 2020

Adjusted EBITDAX $ 189 $ 251 $ 116 $ 83 $ 33

Cash interest (3 ) (49 ) (15 ) (8 ) (7 )

Distributions paidto noncontrolling interest holders:

BSP (14 ) (24 ) (30 ) (30 ) -

Ares - (20 ) (9 ) - (9 )

Asset retirementobligations and (12 ) (4 ) (9 ) (6 ) (3 ) idle well testing



Discretionary cash $ 160 $ 154 $ 53 $ 39 $ 14 flow



ADJUSTED EBITDAX MARGIN

Management uses adjusted EBITDAX margin as a measure of profitability between periods and this measure is generally used by analysts for comparative purposes within the industry.

Successor

Predecessor

Combined(Non-GAAP)

Successor

Predecessor

1st Quarter

1st Quarter

4th Quarter

4th Quarter

4th Quarter

($ millions)

2021

2020

2020

2020

2020

Total revenues

$

363

$

573

$

301

$

152

$

149

Non-cash derivative loss

174

19

127

140

(13)

Revenues, excluding non-cash derivative gains and losses

$

537

$

592

$

428

$

292

$

136

Adjusted EBITDAX margin

35

%

42

%

27

%

28

%

24

%

ADJUSTED EBITDAX MARGIN



Management uses adjusted EBITDAX margin as a measure of profitability betweenperiods and this measure is generally used by analysts for comparative purposeswithin the industry.



Successor Predecessor Combined Successor Predecessor (Non-GAAP)

1st 1st Quarter 4th 4th 4th Quarter Quarter Quarter Quarter

($ 2021 2020 2020 2020 2020millions)

Total $ 363 $ 573 $ 301 $ 152 $ 149 revenues

Non-cashderivative 174 19 127 140 (13) loss

Revenues,excludingnon-cash $ 537 $ 592 $ 428 $ 292 $ 136 derivativegains andlosses

AdjustedEBITDAX 35 % 42 % 27 % 28 % 24 %margin

OPERATING COSTS PER BOE

The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSC-type contracts.

Successor

Predecessor

1st Quarter

1st Quarter

($ per Boe)

2021

2020

Energy operating costs (a)

$

4.70

$

3.71

Gas processing costs

0.53

0.67

Non-energy operating costs (b)

13.10

13.00

Operating costs

$

18.33

$

17.38

Excess costs attributable to PSC-type contracts

(1.61

)

(0.90

)

Operating costs, excluding effects of PSC-type contracts

$

16.72

$

16.48

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

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

OPERATING COSTS PER BOE



The reporting of our PSC-type contracts creates a difference between reportedoperating costs, which are for the full field, and reported volumes, which areonly our net share, inflating the per barrel operating costs. The followingtable presents operating costs after adjusting for the excess costsattributable to PSC-type contracts.



Successor Predecessor

1st Quarter 1st Quarter

($ per Boe) 2021 2020

Energy operating costs ^(a) $ 4.70 $ 3.71

Gas processing costs 0.53 0.67

Non-energy operating costs ^(b) 13.10 13.00

Operating costs $ 18.33 $ 17.38

Excess costs attributable to PSC-type contracts (1.61 ) (0.90 )

Operating costs, excluding effects of PSC-type $ 16.72 $ 16.48 contracts



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

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

Attachment 3

PRODUCTION STATISTICS

Successor

Predecessor

Net

1st Quarter

1st Quarter

Oil, NGLs and Natural Gas Production Per Day

2021

2020

Oil (MBbl/d)

San Joaquin Basin

38

47

Los Angeles Basin

20

26

Ventura Basin

2

4

Total

60

77

NGLs (MBbl/d)

San Joaquin Basin

12

14

Total

12

14

Natural Gas (MMcf/d)

San Joaquin Basin

135

152

Los Angeles Basin

1

2

Ventura Basin

4

6

Sacramento Basin

20

23

Total

160

183

Total Production (MBoe/d)

99

121

Successor

Predecessor

Gross Operated and Net Non-Operated

1st Quarter

1st Quarter

Oil, NGLs and Natural Gas Production Per Day

2021

2020

Oil (MBbl/d)

San Joaquin Basin

44

55

Los Angeles Basin

27

31

Ventura Basin

3

4

Total

74

90

NGLs (MBbl/d)

San Joaquin Basin

13

14

Total

13

14

Natural Gas (MMcf/d)

San Joaquin Basin

144

162

Los Angeles Basin

8

10

Ventura Basin

5

6

Sacramento Basin

24

30

Total

181

208

Total Production (MBoe/d)

117

139

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.

Attachment 3

PRODUCTION STATISTICS

Successor Predecessor

Net 1st Quarter 1st Quarter

Oil, NGLs and Natural Gas Production Per Day 2021 2020

Oil (MBbl/d)

San Joaquin Basin 38 47

Los Angeles Basin 20 26

Ventura Basin 2 4

Total 60 77



NGLs (MBbl/d)

San Joaquin Basin 12 14

Total 12 14



Natural Gas (MMcf/d)

San Joaquin Basin 135 152

Los Angeles Basin 1 2

Ventura Basin 4 6

Sacramento Basin 20 23

Total 160 183



Total Production (MBoe/d) 99 121



Successor Predecessor

Gross Operated and Net Non-Operated 1st Quarter 1st Quarter

Oil, NGLs and Natural Gas Production Per Day 2021 2020

Oil (MBbl/d)

San Joaquin Basin 44 55

Los Angeles Basin 27 31

Ventura Basin 3 4

Total 74 90



NGLs (MBbl/d)

San Joaquin Basin 13 14

Total 13 14



Natural Gas (MMcf/d)

San Joaquin Basin 144 162

Los Angeles Basin 8 10

Ventura Basin 5 6

Sacramento Basin 24 30

Total 181 208



Total Production (MBoe/d) 117 139

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.

Attachment 4

PRICE STATISTICS

Successor Predecessor

1st Quarter 1st Quarter

2021 2020

Realized Prices

Oil with hedge ($/Bbl) $ 53.73 $ 55.50

Oil without hedge ($/Bbl) $ 60.81 $ 50.78



NGLs ($/Bbl) $ 48.77 $ 29.28



Natural gas ($/Mcf) $ 3.29 $ 2.25



Index Prices

Brent oil ($/Bbl) $ 61.10 $ 50.96

WTI oil ($/Bbl) $ 57.84 $ 46.17

NYMEX gas ($/MMBtu) $ 2.72 $ 2.05



Realized Prices as Percentage of Index Prices

Oil with hedge as a percentage of Brent 88 % 109 %

Oil without hedge as a percentage of Brent 100 % 100 %



Oil with hedge as a percentage of WTI 93 % 120 %

Oil without hedge as a percentage of WTI 105 % 110 %



NGLs as a percentage of Brent 80 % 57 %

NGLs as a percentage of WTI 84 % 63 %



Natural gas as a percentage of NYMEX 121 % 110 %

Attachment 5

1ST QUARTER 2021 DRILLING ACTIVITY

San Joaquin

Los Angeles

Ventura

Sacramento

Wells Drilled

Basin

Basin

Basin

Basin

Total

Development Wells

Primary

17

-

-

-

17

Waterflood

-

-

-

-

-

Steamflood

-

-

-

-

-

Unconventional

-

-

-

-

-

Total (1)

17

-

-

-

17

(1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.

Attachment 5

1ST QUARTER 2021 DRILLING ACTIVITY

San Los Ventura Sacramento Joaquin Angeles

Wells Drilled Basin Basin Basin Basin Total



Development Wells

Primary 17 - - - 17

Waterflood - - - - -

Steamflood - - - - -

Unconventional - - - - -

Total^ (1) 17 - - - 17



(1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.

Attachment 6

CRUDE OIL HEDGESAS OF APRIL 30, 2021

January -

Q2 Q3 Q4 1H 2H October 2021 2021 2021 2022 2022 2023



Sold Calls:

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

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



Purchased Puts:

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

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



Sold Puts:

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

Weighted-averageBrent price per $31.41 $30.00 $32.00 $32.00 $32.00 -barrel



Swaps:

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

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

Attachment 7

2021E TOTAL YEAR GUIDANCE

Total Year 2021E

Total Production (Mboe/d)

96 - 99

Oil Production (Mbo/d)

60 - 62

Operating Costs ($ millions)

$615 - $630

General and administrative expenses ($ millions)

$180 - $190

Capital ($ millions)

$185 - $210

Free cash flow ($ millions)

$250 - $350

View source version on businesswire.com: https://www.businesswire.com/news/home/20210513005306/en/

CONTACT: Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com

CONTACT: Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com