California Resources Corporation Announces Fourth Quarter 2020 and Full Year Results

SANTA CLARITA, Calif.--(BUSINESS WIRE)--California Resources Corporation (NYSE: CRC), an independent California-based oil and natural gas exploration and production company, today reported fourth quarter and full year 2020 results. Operational and financial highlights were as follows:

2020 Fourth Quarter and Full Year Highlights

• For the full year of 2020, CRC reported net income of $1,871 million and an adjusted net loss attributable to common stock¹ of $257 million, excluding unusual and infrequent items primarily related to CRC’s bankruptcy proceedings and asset impairments
• For the full year of 2020, reported net cash provided by operating activities of $106 million while generating free cash flow¹ of $172 million, excluding $113 million of one time bankruptcy related fees
• For the full year of 2020, reported adjusted EBITDAX¹ of $489 million with an adjusted EBITDAX margin¹ of 28%
• For the fourth quarter of 2020, produced an average of 103,000 net barrels of oil equivalent (BOE) per day, including 63,000 barrels per day of oil and an average of 111,000 net BOE per day, including 69,000 barrels per day of oil for the full year 2020
• Exited 2020 with an average daily net production of 102,000 BOE per day, including 63,000 barrels per day of oil
• Decreased operating costs, on a per BOE basis, by 19% to $15.45 in 2020 from $19.16 in 2019
• Published third annual Sustainability Report showcasing positive progress on CRC's 2030 Sustainability Goals and secured a top score at CDP’s Leadership Level
• Completed a financial restructuring and emerged from Chapter 11 bankruptcy with a simplified balance sheet and ample liquidity

Other Highlights

• In January 2021, CRC further simplified its balance sheet by completing an offering of $600 million of 7.125% senior unsecured notes due 2026. The net proceeds of $590 million were used to repay in full CRC's Second Lien Term Loan and senior secured notes issued by its subsidiary Elk Hills Power, LLC. The remaining proceeds were used to pay down a portion of CRC's Revolving Credit Facility
• Consistent with the Company’s new strategic direction and low-cost operator focus, CRC has implemented a number of personnel-related cost reduction initiatives to further optimize its organizational structure. Excluding one-time severance charges, these personnel related changes are expected to reduce the compensation expense component of CRC’s 2021 operating expenses by approximately $15 million per year and general and administrative expenses by approximately $50 million per year from its 2020 levels

Mac McFarland, CRC's Chairman and Interim Chief Executive Officer, commented, "We continued our strategic repositioning efforts, making progress on sustainable cost reductions and resuming prudent capital and maintenance spending. CRC will host a Strategy Day on March 18, 2021, and we look forward to providing further details of our full-scale business review and our strategic re-alignment at that time."

Fresh Start Accounting and Predecessor and Successor Periods

Upon emergence from Chapter 11 bankruptcy proceedings on October 27, 2020, CRC adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings. Under fresh start accounting, the reorganized entity is considered a new reporting entity. CRC applied fresh start accounting as of October 31, 2020, an accounting convenience date, and the reorganization value of the emerging entity was assigned to individual assets and liabilities based on their estimated relative fair values. As such, fresh start accounting was reflected on the Company's consolidated balance sheet as of October 31, 2020. 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.

Fourth Quarter 2020 Results

	Fourth Quarter
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ and shares in millions, except per share amounts)	2020		2020		2020		2019
Statements of Operations:
Revenues
Total revenues	152		149		301		610
Costs and Other
Total costs and other	258		151		409		508
Operating (loss) income	(106)		(2)		(108)		102
Net (Loss) Income Attributable to Common Stock	$	(123)	$	3,985	$	3,862	$	(67)
Net (loss) income attributable to common stock per share - diluted^1	$	(1.48)	$	80.20	$	—	$	(1.36)
Adjusted net income (loss)^1	$	28	$	(20)	$	8	$	36
Adjusted net income (loss) per share - diluted^1	$	0.34	$	(0.40)	$	—	$	0.73
Weighted-average common shares outstanding - diluted	83.3		49.5		—		49.2
Adjusted EBITDAX^1	$	83	$	33	$	116	$	308

	Fourth Quarter
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ in millions)	2020		2020		2020		2019
Cash Flow Data:
Net cash (used) provided by operating activities	$	(12)	$	(23)	$	(35)	$	136
Net cash used by investing activities	$	(7)	$	(2)	$	(9)	$	(103)
Net cash (used) provided by financing activities	$	(156)	$	106	$	(50)	$	(38)

Full Year 2020 Results

	Total Year
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ and shares in millions, except per share amounts)	2020		2020		2020		2019
Statements of Operations:
Revenues
Total revenues	152		1,407		1,559		2,634
Costs and Other
Total costs and other	258		3,186		3,444		2,205
Operating (loss) income	(106)		(1,779)		(1,885)		429
Net (Loss) Income Attributable to Common Stock	$	(123)	$	1,889	$	1,766	$	(28)
Net (loss) income attributable to common stock per share - diluted	$	(1.48)	$	40.42	$	—	$	(0.57)
Adjusted net income (loss)^1	$	28	$	(285)	$	(257)	$	70
Adjusted net income (loss) per share - diluted^1	$	0.34	$	(2.98)	$	—	$	1.40
Weighted-average common shares outstanding - diluted	83.3		49.6		—		49.2
Adjusted EBITDAX^1	$	83	$	406	$	489	$	1,142

	Total Year
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ in millions)	2020		2020		2020		2019
Cash Flow Data:
Net cash (used) provided by operating activities	$	(12)	$	118	$	106	$	676
Net cash used by investing activities	$	(7)	$	(30)	$	(37)	$	(394)
Net cash (used) provided by financing activities	$	(156)	$	98	$	(58)	$	(282)

Review of Operating and Financial Results

Total daily net production volumes decreased 16% from 123,000 BOE per day for the fourth quarter of 2019 to 103,000 BOE per day for the fourth quarter of 2020. The decrease from the same prior-year period over CRC's low to mid-teens natural decline rate was primarily due to 2,000 BOE per day of shut-in production driven by the collapse in commodity prices and power outages, lower capital investment, and reduction of well repair work. On an annual basis, total daily net production volumes decreased 13% year-over-year, from 128,000 BOE per day in 2019 to 111,000 BOE per day in 2020. The decrease from the same prior-year period was primarily due a reduced capital program, approximately 3,000 BOE per day of shut-in production, the full year impact of the Lost Hills divestiture and reduction of well repair work. Production sharing contracts in our Long Beach assets increased CRC's share of oil production by approximately 2,100 and 2,700 barrels per day in the fourth quarter and full year of 2020 compared to the same prior-year periods, respectively. CRC exited 2020 with average daily net production of 102,000 BOE per day, including 63,000 barrels per day of oil. See Attachment 2 for further information on production information.

Realized crude oil prices, including the effect of settled hedges, decreased by $25.82 per barrel from $70.21 in the fourth quarter of 2019 to $44.39 per barrel in the fourth quarter of 2020. On an annual basis, realized crude oil prices, including the effect of settled hedges, decreased by $25.12 per barrel from $68.65 in 2019 to $43.53 per barrel. Brent realized prices were lower in 2020 compared to the same prior-year period due to the combination of the supply increase caused by the Saudi-Russia price war that began earlier in the year and the continuation of severe demand decline caused by shelter-in-place orders related to the COVID-19 pandemic. Nevertheless, in 2020, CRC's oil realizations continued to favorably benefit from Brent linked pricing as compared to other U.S. benchmarks. See Attachment 5 for further information on realizations.

Adjusted EBITDAX¹ for the fourth quarter of 2020 was $116 million and cash used in operating activities was $35 million. On an annual basis, adjusted EBITDAX¹ was $489 million and cash provided by operating activities was $106 million. For the fourth quarter of 2020, free cash flow¹ was ($6) million, excluding $39 million of one-time costs incurred relating to CRC's bankruptcy, after taking into account CRC's internally funded capital of $10 million. For the full year, free cash flow¹ was $172 million, excluding $113 million of one-time bankruptcy related fees, after taking into account CRC's internally funded capital of $47 million.

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 legal and professional fees related to our bankruptcy proceedings during 2020 as a supplemental measure of our free cash flow.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions)	2020		2019		2020		2019
Net cash provided by operating activities	$	(35)	$	136	$	106	$	676
Capital investments	(10)		(62)		(47)		(455)
Free cash flow^1	(45)		74		59		221
BSP funded capital	—		—		—		48
Free cash flow, after internally funded capital^1	$	(45)	$	74	$	59	$	269
Professional fees related to our bankruptcy	39		—		113		—
Free cash flow, excluding professional fees related to our bankruptcy^1	$	(6)	$	74	$	172	$	269

Operating costs for the fourth quarter of 2020 were $165 million, compared to $211 million for the fourth quarter of 2019. For the full year 2020, operating costs were $625 million, compared to $895 million in 2019. The decrease was primarily due to efficiencies and streamlining of operations, reduced operating costs from shut-in wells as well as lower activity levels, such as downhole maintenance. Operating costs per BOE are presented below:

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.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ per Boe)	2020		2019		2020		2019
Operating costs	$	17.42	$	18.67	$	15.45	$	19.16
Excess costs attributable to PSC-type contracts	(1.13)		(1.35)		(0.89)		(1.46)
Operating costs, excluding effects of PSC-type contracts	$	16.29	$	17.32	$	14.56	$	17.70

G&A expenses were $59 million for the fourth quarter of 2020, compared to $62 million in the same prior-year period. For the full year of 2020, G&A expenses were $252 million, compared to $290 million in 2019. The decrease in G&A expenses resulted from workforce reductions, cost saving efforts and a decline in spending across a number of cost categories. These savings were partially offset by the cost of obtaining additional directors and officers insurance related to the Chapter 11 cases, lower capitalized salary costs as a result of suspending the capital program beginning in March 2020 as well a slight increase in employee incentive awards due to changes to the variable portion of the incentive compensation program in May 2020, which had the effect of increasing CRC's cash-settled awards to target and achieving a higher target payout on performance metrics.

CRC reported taxes other than on income of $23 million for the fourth quarter of 2020, compared to $38 million for the same prior-year period. For the full year of 2020, CRC reported taxes other than on income of $144 million, compared to $157 million in 2019. The decrease primarily resulted from reduced emissions in 2020 as compared to 2019 due to lower activity levels, including shut-in wells, and better than expected market pricing on the purchase of greenhouse gas emissions credits. Exploration expense was $2 million and $11 million for the fourth quarter of 2020 and for the whole year, respectively, mostly due to limited exploration activity in 2020 as a result of the lower commodity price environment.

Total internally funded capital invested during the fourth quarter of 2020 was $10 million. For the full year of 2020, total capital invested was $140 million, of which $47 million was internally funded by CRC. CRC's JV partners Macquarie Infrastructure and Real Assets Inc. (MIRA) and Alpine Energy Capital, LLC (Alpine) invested an additional $1 million and $92 million, respectively, which are excluded from CRC's consolidated results.

Balance Sheet and Liquidity Update

In January 2021, CRC completed an offering of $600 million of 7.125% senior unsecured notes due 2026. The net proceeds of $590 million were used to repay in full the second lien term loan and all outstanding senior secured notes due 2027 issued by CRC's subsidiary Elk Hills Power, LLC, with the remaining $90 million used to pay down a portion of the Revolving Credit Facility. As of December 31, 2020, CRC had liquidity of $335 million, which consisted of $28 million in unrestricted cash and $307 million of available borrowing capacity under its Revolving Credit Facility. After giving effect to the January 2021 debt issuance discussed above, CRC would have had, on a pro forma basis, liquidity of $425 million as of December 31, 2020, which consisted of $28 million in unrestricted cash and $397 million of available borrowing capacity under its Revolving Credit Facility. As of March 01, 2021, CRC had an undrawn revolving credit facility, $125 million in letters of credit outstanding and liquidity of approximately $475 million.

Organization Changes

During the second half of 2020, CRC implemented organizational changes that resulted in a 12% reduction of overall headcount to approximately 1,100 employees. Subsequent to the quarter-end, CRC took steps to further align the cost structure with the objective to focus around core assets and cost performance. This included decisions to reduce the size of its management team and to realign several functions which resulted in further headcount and cost reductions. During the first quarter of 2021, CRC further reduced its headcount by an additional 9% to approximately 1,000 employees.

Excluding one-time severance charges, these personnel related changes are expected to reduce the compensation expense component of CRC’s 2021 operating expenses by approximately $15 million per year and general and administrative expenses by approximately $50 million per year from its 2020 levels.

Operational Update

In the fourth quarter of 2020, CRC operated no drilling rigs. The San Joaquin basin produced 74,000 net BOE per day. The Los Angeles basin produced 23,000 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.

2021 Capital Budget

CRC's capital program will be dynamic in response to oil market volatility while focusing on maintaining strong liquidity and maximizing free cash flow. The 2021 capital program will target reinvestment of approximately 50% of anticipated available cash flow from operations at current commodity prices. CRC's 2021 capital program is anticipated to be between $200 and $225 million, including approximately $40 million of mechanical integrity and midstream turnaround activities deferred from 2020 to 2021. The current plan anticipates CRC to gradually raise quarterly investment throughout the year if the commodity environment continues to strengthen. CRC will maintain the flexibility to adjust its capital program in response to declining market conditions.

Reserves

As of December 31, 2020, CRC had estimated proved reserves totaling 442 million BOE, of which 382 million BOE was proved developed and 60 million BOE was proved undeveloped. The estimated future net cash flows of our proved reserve volumes had a PV-10 value of $2.43 billion. These estimates were based on SEC pricing and the average realized prices for estimating CRC's proved reserves were $42.35 per barrel for oil, $26.42 per barrel for NGLs and $2.28 per Mcf for natural gas.

PV-10 AND STANDARDIZED MEASURE
The following table presents a reconciliation of the GAAP financial measure of Standardized Measure of discounted future net cash flows (Standardized Measure) to the non-GAAP financial measure of PV-10:
($ millions)	December 31, 2020
Standardized Measure of discounted future net cash flows	$	1,932
Present value of future income taxes discounted at 10%	494
PV-10 of cash flows^(*)	$	2,426
(*) PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.

Based on average realized prices of $55 per barrel of oil and $2.50 per Mcf for natural gas, CRC's estimated proved reserves would be 515 million BOE, including 441 million BOE of proved developed and 74 million BOE of proved undeveloped reserves. Management's internal estimate of PV-10 value at these prices would be approximately $4.75 billion².

ESG Update

As a dependable and reliable energy producer in the State of California, in 2020, CRC maintained the highest CDP ranking among all U.S. oil and gas companies, tying for first with one other U.S.-based E&P with global operations, and released the third annual Sustainability report with expanded disclosures. Underscoring the Company's commitment to safe and responsible production, CRC'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, continue to be directly tied to the performance-based compensation of its executives, senior managers and employees. The new Board of Directors will continue to highlight, monitor and provide guidance on CRC ESG efforts, including a strong commitment to sustainability, HSE and community engagement.

Hedging Update as of February 28, 2021

CRC will utilize its hedging program to ensure strong cash flows in nearly any commodity price environment and will target approximately 80% of anticipated production. The current strategy includes a mix of swaps and options to ensure CRC’s ability to generate free cash flow and is also aligned with CRC’s reserve-based lending (RBL) requirements. See Attachment 7 for further information on CRC's current hedges.

2021 Strategy Day

On March 18, 2021, at 1 p.m. Eastern Time/10 a.m. Pacific Time, CRC will host a virtual Strategy Day to review the Company’s strategic repositioning, expected outcomes of the new strategic alignment and 2021 guidance. Participants can preregister here for the live webcast or access in the Investor Relations section of CRC.com the day of the event. A digital replay of the event will be archived for approximately 90 days and supplemental slides for the event will also be available in the Investor Relations section on www.crc.com.

^1See Attachment 3 for the non-GAAP financial measures of adjusted EBITDAX, adjusted EBITDAX margin, operating costs per BOE (excluding effects of PSC-type contracts), adjusted net income (loss), discretionary cash flow and free cash flow, including reconciliations to their most directly comparable GAAP measure, where applicable.

^2GAAP does not prescribe a standardized measure of reserves on a basis other than SEC pricing. As such, no standardized measure of proved reserves using $55 per barrel for oil and $2.50 per Mcf for natural gas has been provided.

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
• 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
	Fourth Quarter
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ and shares in millions, except per share amounts)	2020		2020		2020		2019
Statements of Operations:
Revenues
Oil and natural gas sales	$	237	$	105	$	342	$	550
Net derivative gain (loss) from commodity contracts	(141)		16		(125)		(28)
Other revenue
Trading revenue	38		15		53		56
Electricity sales	15		11		26		24
Other	3		2		5		8
Total revenues	152		149		301		610
Costs and Other
Operating costs	114		51		165		211
General and administrative expenses	40		19		59		62
Depreciation, depletion and amortization	34		32		66		114
Taxes other than on income	10		13		23		38
Exploration expense	1		1		2		4
Other expenses, net
Trading costs	24		11		35		31
Electricity cost of sales	10		6		16		17
Transportation costs	8		4		12		10
Other	17		14		31		21
Total costs and other	258		151		409		508
Operating (Loss) Income	(106)		(2)		(108)		102
Non-Operating (Loss) Income
Reorganization items, net	(3)		3,994		3,991		—
Interest and debt expense, net	(11)		(6)		(17)		(90)
Net gain on early extinguishment of debt	—		—		—		18
Other non-operating expenses	(5)		9		4		(54)
(Loss) Income Before Income Taxes	(125)		3,995		3,870		(24)
Income tax provision	—		—		—		(1)
Net (Loss) Income	(125)		3,995		3,870		(25)
Net loss (income) attributable to noncontrolling interests	2		(10)		(8)		(42)
Net (Loss) Income Attributable to Common Stock	$	(123)	$	3,985	$	3,862	$	(67)
Net (loss) income attributable to common stock per share - basic^1	$	(1.48)	$	80.20	$	—	$	(1.36)
Net (loss) income attributable to common stock per share - diluted^1	$	(1.48)	$	80.20	$	—	$	(1.36)
Adjusted net income (loss)	$	28	$	(20)	$	8	$	36
Adjusted net income (loss) per share - basic	$	0.34	$	(0.40)	$	—	$	0.73
Adjusted net income (loss) per share - diluted	$	0.34	$	(0.40)	$	—	$	0.73
Weighted-average common shares outstanding - basic	83.3		49.5		—		49.1
Weighted-average common shares outstanding - diluted	83.3		49.5		—		49.2
Adjusted EBITDAX	$	83	$	33	$	116	$	308
Effective tax rate	0%		0%		0%		4%

	Total Year
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ and shares in millions, except per share amounts)	2020		2020		2020		2019
Statements of Operations:
Revenues
Oil and natural gas sales	$	237	$	1,092	$	1,329	$	2,270
Net derivative gain (loss) from commodity contracts	(141)		91		(50)		(59)
Other revenue
Trading revenue	38		124		162		286
Electricity sales	15		86		101		112
Other	3		14		17		25
Total revenues	152		1,407		1,559		2,634
Costs and Other
Operating costs	114		511		625		895
General and administrative expenses	40		212		252		290
Depreciation, depletion and amortization	34		328		362		471
Asset impairments	—		1,736		1,736		—
Taxes other than on income	10		134		144		157
Exploration expense	1		10		11		29
Other expenses, net
Trading costs	24		78		102		201
Electricity cost of sales	10		53		63		68
Transportation costs	8		35		43		40
Other	17		89		106		54
Total costs and other	258		3,186		3,444		2,205
Operating (Loss) Income	(106)		(1,779)		(1,885)		429
Non-Operating (Loss) Income
Reorganization items, net	(3)		4,060		4,057		—
Interest and debt expense, net	(11)		(206)		(217)		(383)
Net gain on early extinguishment of debt	—		5		5		126
Other non-operating expenses	(5)		(84)		(89)		(72)
(Loss) Income Before Income Taxes	(125)		1,996		1,871		100
Income tax provision	—		—		—		(1)
Net (Loss) Income	(125)		1,996		1,871		99
Net loss (income) attributable to noncontrolling interests	2		(107)		(105)		(127)
Net (Loss) Income Attributable to Common Stock	$	(123)	$	1,889	$	1,766	$	(28)
Net (loss) income attributable to common stock per share - basic	$	(1.48)	$	40.59	$	—	$	(0.57)
Net (loss) income attributable to common stock per share - diluted	$	(1.48)	$	40.42	$	—	$	(0.57)

Adjusted net income (loss)	$	28	$	(285)	$	(257)	$	70
Adjusted net income (loss) per share - basic	$	0.34	$	(2.98)	$	—	$	1.41
Adjusted net income (loss) per share - diluted	$	0.34	$	(2.98)	$	—	$	1.40
Weighted-average common shares outstanding - basic	83.3		49.4		—		49.0
Weighted-average common shares outstanding - diluted	83.3		49.6		—		49.2
Adjusted EBITDAX	$	83	$	406	$	489	$	1,142
Effective tax rate	0%		0%		0		1%

	Fourth Quarter
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ in millions)	2020		2020		2020		2019
Cash Flow Data:
Net cash (used) provided by operating activities	$	(12)	$	(23)	$	(35)	$	136
Net cash used by investing activities	$	(7)	$	(2)	$	(9)	$	(103)
Net cash (used) provided by financing activities	$	(156)	$	106	$	(50)	$	(38)

	Total Year
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ in millions)	2020		2020		2020		2019
Cash Flow Data:
Net cash (used) provided by operating activities	$	(12)	$	118	$	106	$	676
Net cash used by investing activities	$	(7)	$	(30)	$	(37)	$	(394)
Net cash (used) provided by financing activities	$	(156)	$	98	$	(58)	$	(282)

	Successor		Predecessor
	December 31,		December 31,
($ and shares in millions)	2020		2019
Selected Balance Sheet Data:
Total current assets	$	329	$	491
Property, plant and equipment, net	$	2,655	$	6,352
Total current liabilities	$	473	$	709
Long-term debt, net	$	597	$	5,023
Other long-term liabilities	$	822	$	720
Mezzanine equity	$	—	$	802
Equity	$	1,182	$	(296)
Outstanding shares	83.3		49.2

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS
	Fourth Quarter
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions)	2020		2020		2020		2019
Non-cash derivative (loss) gain - excluding noncontrolling interest	$	(138)	$	13	$	(125)	$	(67)
Non-cash derivative (loss) gain - noncontrolling interest	(2)		—		(2)		(4)
Total non-cash changes	(140)		13		(127)		(71)
Net (payments) proceeds on settled commodity derivatives	(1)		3		2		43
Net derivative (loss) gain from commodity contracts	$	(141)	$	16	$	(125)	$	(28)

	Total Year
	Successor		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions)	2020		2020		2020		2019
Non-cash derivative (loss) gain - excluding noncontrolling interest	$	(138)	$	(19)	$	(157)	$	(166)
Non-cash derivative (loss) gain - noncontrolling interest	(2)		2		—		(4)
Total non-cash changes	(140)		(17)		(157)		(170)
Net (payments) proceeds on settled commodity derivatives	(1)		108		107		111
Net derivative (loss) gain from commodity contracts	$	(141)	$	91	$	(50)	$	(59)

Attachment 2
PRODUCTION STATISTICS
	Fourth Quarter
Net	Successor	Predecessor	Combined	Predecessor
Oil, NGLs and Natural Gas Production Per Day	2020	2020	2020	2019
Oil (MBbl/d)
San Joaquin Basin	38	38	38	50
Los Angeles Basin	23	23	23	23
Ventura Basin	2	2	2	3
Total	63	63	63	76
NGLs (MBbl/d)
San Joaquin Basin	12	13	13	15
Total	12	13	13	15
Natural Gas (MMcf/d)
San Joaquin Basin	138	139	138	157
Los Angeles Basin	1	1	2	2
Ventura Basin	3	3	3	5
Sacramento Basin	23	19	20	26
Total	165	162	163	190
Total Production (MBoe/d)	103	103	103	123
	Fourth Quarter
Gross Operated and Net Non-Operated	Successor	Predecessor	Combined	Predecessor
Oil, NGLs and Natural Gas Production Per Day	2020	2020	2020	2019
Oil (MBbl/d)
San Joaquin Basin	44	45	45	54
Los Angeles Basin	28	27	28	31
Ventura Basin	3	3	2	4
Total	75	75	75	89
NGLs (MBbl/d)
San Joaquin Basin	13	14	13	15
Total	13	14	13	15
Natural Gas (MMcf/d)
San Joaquin Basin	148	149	148	161
Los Angeles Basin	8	8	8	10
Ventura Basin	3	4	4	5
Sacramento Basin	26	24	25	35
Total	185	185	185	211
Total Production (MBoe/d)	119	119	119	140

Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

	Total Year
Net	Successor	Predecessor	Combined	Predecessor
Oil, NGLs and Natural Gas Production Per Day	2020	2020	2020	2019
Oil (MBbl/d)
San Joaquin Basin	38	42	42	52
Los Angeles Basin	23	25	24	24
Ventura Basin	2	3	3	4
Total	63	70	69	80
NGLs (MBbl/d)
San Joaquin Basin	12	13	13	15
Total	12	13	13	15
Natural Gas (MMcf/d)
San Joaquin Basin	138	147	145	162
Los Angeles Basin	1	2	2	2
Ventura Basin	3	4	4	5
Sacramento Basin	23	21	21	28
Total	165	174	172	197
Total Production (MBoe/d)	103	112	111	128

	Total Year
Gross Operated and Net Non-Operated	Successor	Predecessor	Combined	Predecessor
Oil, NGLs and Natural Gas Production Per Day	2020	2020	2020	2019
Oil (MBbl/d)
San Joaquin Basin	44	49	48	56
Los Angeles Basin	28	30	29	32
Ventura Basin	3	3	3	5
Total	75	82	80	93
NGLs (MBbl/d)
San Joaquin Basin	13	14	14	15
Total	13	14	14	15
Natural Gas (MMcf/d)
San Joaquin Basin	148	157	155	164
Los Angeles Basin	8	9	9	9
Ventura Basin	3	4	4	5
Sacramento Basin	26	27	26	38
Total	185	197	194	216
Total Production (MBoe/d)	119	129	127	144

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

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

Our results of operations, which are presented in accordance with U.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses certain non-GAAP measures to assess our financial condition, results of operations and cash flows. These measures are 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. These measures should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.   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.

ADJUSTED NET INCOME (LOSS)
Management uses a measure called adjusted net income (loss) to provide useful information to investors interested in comparing our core operations between periods and our performance to our peers. This measure is not meant to disassociate the effects of unusual, out-of-period and infrequent items affecting earnings from management's performance but rather is meant to provide useful information to investors 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) attributable to common stock to the non-GAAP financial measure of adjusted net income (loss) and presents the GAAP financial measure of net income (loss) attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net income (loss) per diluted share.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions, except per share amounts)	2020		2019		2020		2019
Net income (loss)	$	3,870	$	(25)	$	1,871	$	99
Net income attributable to noncontrolling interests	(8)		(42)		(105)		(127)
Net income (loss) attributable to common stock	3,862		(67)		1,766		(28)
Unusual, infrequent and other items:
Non-cash derivative loss (gain) from commodities, excluding noncontrolling interest	125		67		157		166
Non-cash derivative loss from interest rate contracts	—		—		—		4
Asset impairments	—		—		1,736		—
Reorganization items, net	(3,991)		—		(4,057)		—
Severance and termination costs	5		45		15		47
Incentive and retention award modifications	—		—		4		—
Net gain on early extinguishment of debt	—		(18)		(5)		(126)
Legal and professional fees related to our reorganization	—		—		65		—
Deficiency payment on pipeline delivery contract	—		—		20		—
Power plant maintenance	—		—		7		—
Write-off of deferred financing costs	—		—		4
Rig termination expenses	2		1		5		3
Ad valorem late payment penalties	—		—		4		—
Other, net	5		8		22		4
Total unusual, infrequent and other items	(3,854)		103		(2,023)		98
Adjusted net income (loss) attributable to common stock	$	8	$	36	$	(257)	$	70
Net income (loss) attributable to common stock per share - diluted	$	—	$	(1.36)	$	—	$	(0.57)
Adjusted net income (loss) per share - diluted	$	—	$	0.73	$	—	$	1.40

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 2020 as a supplemental measure of our free cash flow.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions)	2020		2019		2020		2019
Net cash provided by operating activities	$	(35)	$	136	$	106	$	676
Capital investments	(10)		(62)		(47)		(455)
Free cash flow	(45)		74		59		221
BSP funded capital	—		—		—		48
Free cash flow, after internally funded capital	$	(45)	$	74	$	59	$	269
One-time bankruptcy related fees	39		—		113		—
Free cash flow, excluding one-time bankruptcy related fees	$	(6)	$	74	$	172	$	269

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.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions, except per BOE amounts)	2020		2019		2020		2019
Net (loss) income	$	3,870	$	(25)	$	1,871	$	99
Interest and debt expense, net	17		90		217		383
Depreciation, depletion and amortization	66		114		362		471
Exploration expense	2		4		11		29
Unusual, infrequent and other items ^(a)	(3,854)		103		(2,023)		98
Non-cash items
Accretion expense	11		8		41		36
Stock-settled compensation	1		3		6		13
Post-retirement medical and pension	1		5		4		8
Other non-cash items	2		6		—		5
Adjusted EBITDAX	$	116	$	308	$	489	$	1,142
Net cash provided by operating activities	$	(35)	$	136	$	106	$	676
Cash interest	15		139		95		439
Exploration expenditures	2		3		11		18
Working capital changes	134		30		277		9
Adjusted EBITDAX	$	116	$	308	$	489	$	1,142
Adjusted EBITDAX per Boe	$	12.25	$	27.25	$	12.09	$	24.45
(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.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ millions)	2020		2019		2020		2019
Adjusted EBITDAX	$	116	$	308	$	489	$	1,142
Cash interest	(15)		(139)		(95)		(439)
Distributions paid to noncontrolling interest holders:
BSP	(30)		(16)		(64)		(71)
Ares	(9)		(20)		(70)		(80)
Discretionary cash flow ^(1)	$	62	$	133	$	260	$	552
^(1) Cash used for asset retirement obligations and idle well testing would have reduced Discretionary Cash Flow by $9 million and $8 million for the three months ended December 31, 2020 and 2019, respectively and $17 million and $26 million for the years ended December 31, 2020 and 2019, respectively.

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.
	Fourth Quarter						Total Year
	Combined (Non-GAAP)			Predecessor			Combined (Non-GAAP)			Predecessor
($ millions)	2020			2019			2020			2019
Total revenues	$	301		$	610		$	1,559		$	2,634
Non-cash derivative loss	127			71			157			170
Revenues, excluding non-cash derivative gains and losses	$	428		$	681		$	1,716		$	2,804
Adjusted EBITDAX margin	27		%	45		%	28		%	41		%

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.
	Fourth Quarter				Total Year
	Combined (Non-GAAP)		Predecessor		Combined (Non-GAAP)		Predecessor
($ per Boe)	2020		2019		2020		2019
Operating costs	$	17.42	$	18.67	$	15.45	$	19.16
Excess costs attributable to PSC-type contracts	(1.13)		(1.35)		(0.89)		(1.46)
Operating costs, excluding effects of PSC-type contracts	$	16.29	$	17.32	$	14.56	$	17.70

Attachment 4
CAPITAL INVESTMENTS
	Fourth Quarter
	Successor		Predecessor		Combined		Predecessor
($ millions)	2020		2020		2020		2019
Internally funded capital	$	7	$	3	$	10	$	62
Capital investments not included on our financial statements:
MIRA funded capital	—		—		—		13
Alpine funded capital	(1)		—		(1)		71
Total capital program	$	6	$	3	$	9	$	146

	Total Year
	Successor		Predecessor		Combined		Predecessor
($ millions)	2020		2020		2020		2019
Internally funded capital	$	7	$	40	$	47	$	455
Capital investments not included on our financial statements:
MIRA funded capital	—		1		1		23
Alpine funded capital	(1)		93		92		134
Total capital program	$	6	$	134	$	140	$	612

Attachment 5
PRICE STATISTICS
	Fourth Quarter
	Successor			Predecessor			Combined			Predecessor
	2020			2020			2020			2019
Realized Prices
Oil with hedge ($/Bbl)	$	45.37		$	42.45		$	44.39		$	70.21
Oil without hedge ($/Bbl)	$	45.65		$	40.59		$	43.94		$	64.22
NGLs ($/Bbl)	$	38.00		$	30.57		$	35.45		$	33.81
Natural gas ($/Mcf)	$	3.21		$	2.68		$	3.03		$	3.00
Index Prices
Brent oil ($/Bbl)	$	47.10		$	41.52		$	45.24		$	62.50
WTI oil ($/Bbl)	$	44.21		$	39.55		$	42.66		$	56.96
NYMEX gas ($/MMBtu)	$	2.86		$	2.28		$	2.66		$	2.50
Realized Prices as Percentage of Index Prices
Oil with hedge as a percentage of Brent	96		%	102		%	98		%	112		%
Oil without hedge as a percentage of Brent	97		%	98		%	97		%	103		%
Oil with hedge as a percentage of WTI	103		%	107		%	104		%	123		%
Oil without hedge as a percentage of WTI	103		%	103		%	103		%	113		%
NGLs as a percentage of Brent	81		%	74		%	78		%	54		%
NGLs as a percentage of WTI	86		%	77		%	83		%	59		%
Natural gas as a percentage of NYMEX	112		%	118		%	114		%	120		%

	Total Year
	Successor		Predecessor		Combined		Predecessor
	2020		2020		2020		2019
Realized Prices
Oil with hedge ($/Bbl)	$	45.37	$	43.19	$	43.53	$	68.65
Oil without hedge ($/Bbl)	$	45.65	$	41.21	$	41.89	$	64.83
NGLs ($/Bbl)	$	38.00	$	25.70	$	27.63	$	31.71
Natural gas ($/Mcf)	$	3.21	$	2.11	$	2.28	$	2.87
Index Prices
Brent oil ($/Bbl)	$	47.10	$	42.43	$	43.21	$	64.18
WTI oil ($/Bbl)	$	44.21	$	38.44	$	39.40	$	57.03
NYMEX gas ($/MMBtu)	$	2.86	$	1.95	$	2.10	$	2.67

`

Realized Prices as Percentage of Index Prices
Oil with hedge as a percentage of Brent	96	%	102	%	101	%	107	%
Oil without hedge as a percentage of Brent	97	%	97	%	97	%	101	%
Oil with hedge as a percentage of WTI	103	%	112	%	110	%	120	%
Oil without hedge as a percentage of WTI	103	%	107	%	106	%	114	%
NGLs as a percentage of Brent	81	%	61	%	64	%	49	%
NGLs as a percentage of WTI	86	%	67	%	70	%	56	%
Natural gas as a percentage of NYMEX	112	%	108	%	109	%	107	%

Attachment 6
TOTAL YEAR 2020 DRILLING ACTIVITY
	San Joaquin	Los Angeles	Ventura	Sacramento
Wells Drilled	Basin	Basin	Basin	Basin	Total
Development Wells
Primary	48	—	—	—	48
Waterflood	2	4	—	—	6
Steamflood	—	—	—	—	—
Unconventional	18	—	—	—	18
Total	68	4	—	—	72
Total^(1)	68	4	—	—	72
	San Joaquin	Los Angeles	Ventura	Sacramento
Wells Drilled	Basin	Basin	Basin	Basin	Total
CRC	3	4	—	—	7
Alpine	65	—	—	—	65
Total^(1)	68	4	—	—	72
There were no wells drilled in the fourth quarter of 2020.
^(1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.

Attachment 7
HEDGES - AS OF FEBRUARY 28, 2021
						January -
	Q1 2021	Q2 2021	Q3 2021	Q4 2021	2022	October 2023
Sold Calls:
Barrels per day	19,028	33,537	36,362	36,700	30,783	17,758
Weighted-average Brent price per barrel	$47.88	$48.73	$50.31	$60.70	$59.37	$58.01
Purchased Puts:
Barrels per day	39,148	37,872	36,617	35,483	30,783	17,758
Weighted-average Brent price per barrel	$41.88	$40.00	$40.00	$40.00	$40.00	$40.00
Sold Puts:
Barrels per day	15,659	15,149	14,647	14,193	3,042	—
Weighted-average Brent price per barrel	$35.97	$31.41	$30.00	$32.00	$32.00	—
Swaps:
Barrels per day	8,524	9,639	9,063	8,922	6,576	5,919
Weighted-average Brent price per barrel	$44.54	$46.35	$47.18	$48.57	$46.29	$47.57
The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the BSP JV could affect the timing of the redemption of BSP's preferred interest.