California Resources Corporation Announces Third Quarter 2020 Results

Rhea-AI Summary

California Resources Corporation (NYSE: CRC) reported a net loss of $29 million for Q3 2020, with an adjusted net loss of $55 million. The company emerged from Chapter 11 bankruptcy with a new capital structure, while facing significant challenges including a 17% decline in production year-over-year. Average net production was 106,000 BOE per day. Despite lower crude prices at $42.15 per barrel, CRC achieved free cash flow of $44 million. The restructuring eliminated pre-filing debt and established a new liquidity framework for operations.

Positive

• Successfully emerged from Chapter 11 bankruptcy with a new capital structure.
• Generated $44 million in free cash flow for Q3 2020.
• Reported adjusted EBITDAX of $103 million with a margin of 25%.
• Reduced production costs from $18.82 to $14.52 per BOE.

Negative

• Reported a net loss of $29 million for Q3 2020.
• Total daily net production decreased 17% year-over-year.
• Average realized crude oil prices fell $26.26 per barrel from the previous year.

SANTA CLARITA, Calif.--(BUSINESS WIRE)--California Resources Corporation (NYSE: CRC), an independent California-based oil and gas exploration and production company, today reported a net loss attributable to common stock of $29 million for the third quarter of 2020, and adjusted net loss¹ of $55 million. GAAP reporting requires the accounting return from the non-controlling interest in the Ares JV upon our emergence from bankruptcy to be taken into account in determining earnings per share. Accordingly, CRC reported net income of $2.20 per diluted share for the third quarter of 2020, or adjusted net income¹ of $1.68 per diluted share. Operational and financial highlights for the third quarter of 2020 were as follows:

Highlights

• Completed a financial restructuring and emerged from Chapter 11 bankruptcy with $535 million of net debt² and $350 million of liquidity³
• Reported adjusted EBITDAX¹ of $103 million; adjusted EBITDAX margin¹ of 25%; net cash provided by operating activities of $48 million; and free cash flow¹ of $44 million after internally funded capital
• Delivered average net production of 106,000 barrels of oil equivalent (BOE) per day including 64,000 barrels per day of oil
• Optimized CRC and flattened the organization for a leaner structure, reducing costs to enhance profitability in the current Brent price environment
• Published third annual Sustainability Report showcasing 2030 Sustainability Goals and 2019 ESG Performance data

Todd A. Stevens, CRC's President and Chief Executive Officer, commented, “I am proud of our team's performance as we navigated through the recent Chapter 11 restructuring while continuing to safely operate amidst the ongoing worldwide pandemic. I strongly believe that our new capital structure and organizational design provide a solid foundation to create substantial value and deliver significant shareholder returns. We look forward to further developing our vast portfolio while generating free cash flow, advancing our sustainability projects and ensuring that we can continue to provide energy to California by Californians for decades to come.”

Mr. Stevens continued, "Given the state’s energy challenges, maintaining responsible California production without interruption is more important than ever. California currently imports over 70% of the oil and 90% of the natural gas it uses daily. California needs all of its native oil and gas for personal protective equipment, hand sanitizer, jet fuel and bunker fuel for ships in our ports, in addition to gasoline, diesel and many other products essential to our quality of life."

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

2 Net debt is net of unrestricted cash of approximately $72 million and $118 million used to cash collateralize on an interim basis certain letters of credit that were outstanding under CRC’s senior debtor-in-possession credit facility at the time of our emergence.

3 Liquidity includes $72 million of unrestricted cash and approximately $278 million of availability on our Revolving Credit Facility.

Third Quarter 2020 Results

For the third quarter of 2020, CRC reported a net loss attributable to common stock (CRC net loss) of $29 million, or net income of $2.20 per diluted share after accounting for a return from the noncontrolling interest in the Ares JV, compared to a net income attributable to common stock of $94 million, or $1.89 per diluted share, for the same period of 2019. Adjusted net loss¹ for the third quarter of 2020 was $55 million, or adjusted net income¹ of $1.68 per diluted share, compared to adjusted net income¹ of $17 million, or $0.35 per diluted share, for the same period in 2019. Third quarter 2020 adjusted net loss¹ excluded unusual and infrequent items including a net gain of $66 million from reorganization items, $15 million of Chapter 11 transaction costs, $10 million of severance expenses and other net charges of $15 million. Third quarter 2019 adjusted net income¹ excluded a net gain of $82 million on debt repurchases and non-cash losses on commodity derivatives of $6 million.

Adjusted EBITDAX¹ for the third quarter of 2020 was $103 million and cash provided by operating activities was $48 million. Free cash flow¹ was $44 million after taking into account CRC's internally funded capital of $4 million.

Total daily net production volumes decreased 17% year-over-year, from 128,000 BOE per day for the third quarter of 2019 to 106,000 BOE per day for the third quarter of 2020. The decrease from the same prior-year period over our mid-teens natural decline rate was primarily due to shut-in production driven by the collapse in commodity prices, power outages and reduced well repair work. PSC-type contracts positively impacted our oil production by nearly 1,000 barrels per day in the third quarter of 2020 compared to the same prior-year period. Oil volumes in the third quarter of 2020 averaged 64,000 barrels per day, NGL volumes averaged 14,000 barrels per day and natural gas volumes averaged 168 million cubic feet per day.

Our realized crude oil prices, including the effect of settled hedges, decreased by $26.26 per barrel from $68.41 in the third quarter of 2019 to $42.15 per barrel in the third quarter of 2020. Brent realized prices were lower in the three months ended September 30, 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 COVID-19. In the third quarter of 2020, hedge settlements increased our realized crude oil prices by $0.32 per barrel compared to an increase of $5.56 per barrel in the same prior-year period. Realized NGL prices were $25.16 per barrel, up $1.61 per barrel over the prior-year period due to improvements in negotiated sales differentials along with stronger NGL values relative to crude. Realized natural gas prices were $2.22 per thousand cubic feet (Mcf) for the third quarter of 2020, $0.51 per Mcf lower than the same prior-year period increased natural gas production and higher inventories across the U.S. primarily due to shelter-in-place orders related to COVID-19, partially offset by fewer infrastructure constraints within local California markets in 2020 compared to 2019.

Production costs for the third quarter of 2020 were $141 million, compared to $221 million for the third quarter of 2019. The decrease was primarily due to efficiencies and streamlining of our operations, workforce reductions and reduced activity levels, such as well repair work, in response to the current economic environment. On a per barrel basis, for the same comparative periods, production costs were $14.52 and $18.82, respectively. Excluding the effect of PSC-type contracts, production costs per BOE¹ for the third quarter of 2020 and 2019 were $13.37 and $17.44, respectively.

G&A expenses were $64 million for the third quarter of 2020, compared to $66 million for the same prior-year period. Third quarter G&A expenses decreased primarily due to ongoing cost saving efforts, workforce reductions and a decline in spending across a number of cost categories. These reductions were offset by an increase in cash costs related to changes to our compensation plans prior to our bankruptcy filing and higher payout on pre-established performance metrics on the incentive portion of these awards in the third quarter of 2020. Excluding the cost of employee incentive awards, the 2020 third quarter G&A was $44 million, down $11 million from $55 million in the third quarter of 2019.

CRC reported taxes other than on income of $42 million for the third quarter of 2020, consistent with the same prior-year period. Exploration expense was $2 million for the third quarter of 2020, $3 million less than the same prior-year period due to lower activity.

Total internally funded capital invested during the third quarter of 2020 was $4 million.

Nine-Month 2020 Results

For the first nine months of 2020, CRC reported a net loss attributable to common stock (CRC net loss) of $2,096 million, or $39.64 per diluted share after accounting for a return from the noncontrolling interest in the Ares JV in the third quarter of 2020, compared to a net income attributable to common stock of $39 million, or $0.77 per diluted share, for the same period of 2019. Adjusted net loss¹ for the first nine months of 2020 was $265 million, or $2.57 per diluted share, compared to adjusted net income¹ of $34 million, or $0.69 per diluted share, for the same period in 2019. The first nine months of 2020 adjusted net loss¹ excluded unusual and infrequent items including $1,736 million of asset impairments, $64 million of Chapter 11 costs, a gain of $66 million on reorganization items, net, and other net losses of $97 million. The first nine months of 2019 adjusted net income¹ excluded a net gain of $108 million from debt repurchases, $99 million of non-cash derivative losses, and a net $4 million charge related to other unusual and infrequent items.

Adjusted EBITDAX¹ for the first nine months of 2020 was $373 million and cash provided by operating activities was $141 million. Free cash flow¹ was $104 million after taking into account CRC's internally funded capital of $37 million.

Total daily net production volumes decreased 13% year-over-year, from 130,000 BOE per day for the first nine months of 2019 to 113,000 BOE per day for the first nine months of 2020. The decrease over the same prior-year period was primarily due to very limited capital investment, approximately 3,000 BOE per day of average shut-in production during the 2020 period, the Lost Hills divestiture, lower well repair work and other factors. PSC-type contracts positively impacted our oil production by over 2,800 barrels per day in the first nine months of 2020 compared to the prior-year period. Oil volumes in the first nine months of 2020 averaged 70,000 barrels per day, NGL volumes averaged 14,000 barrels per day and natural gas volumes averaged 175 million cubic feet per day.

Our realized crude oil prices, including the effect of settled hedges, decreased by $24.89 per barrel from $68.16 in the first nine months of 2019 to $43.27 per barrel in the first nine months of 2020. In the first nine months of 2020, hedge settlements increased our realized crude oil prices by $2.00 per barrel compared to an increase of $3.13 per barrel in the same prior-year period. Realized NGL prices were $25.17 per barrel, down $5.87 per barrel over the prior-year period. Realized natural gas prices were $2.05 per thousand cubic feet (Mcf) for the first nine months of 2020, $0.77 per Mcf lower than the same prior-year period.

Production costs for the first nine months of 2020 were $460 million, compared to $684 million for the first nine months of 2019. The decrease was primarily due to efficiencies and streamlining of our operations, workforce reductions and reduced work schedules, as well as lower activity levels, such as well repair work, in response to the current environment. On a per barrel basis, for the same comparative periods, production costs were $14.85 and $19.32, respectively. Excluding the effect of PSC-type contracts, production costs per BOE¹ for the first nine months of 2020 and 2019 were $14.03 and $17.82, respectively.

G&A expenses were $193 million for the first nine months of 2020, compared to $228 million for the same prior-year period. The decrease was primarily attributable to cost saving efforts, workforce reductions and a decline in spending across a number of cost categories.

CRC reported taxes other than on income of $121 million for the first nine months of 2020, consistent with the same prior-year period. Exploration expense was $9 million for the first nine months of 2020, down from $25 million in the same prior-year period due to lower activity.

Total capital invested during the first nine months of 2020 was $131 million. CRC internally funded $37 million. CRC's JV partners Macquarie Infrastructure and Real Assets Inc. (MIRA) and Alpine invested an additional $1 million and $93 million, respectively, which are excluded from CRC's consolidated results.

Emergence and Balance Sheet Update

Subsequent to quarter-end, CRC emerged from Chapter 11 bankruptcy with a new balance sheet. The restructuring eliminated all pre-filing debt and the noncontrolling interests in CRC's midstream JV. As a result, CRC's new capital structure consists of a $1.2 billion reserve-based lending Revolving Credit Facility with a commitment level of $540 million, $300 million of Secured Notes and a $200 million Second Lien Term Loan. CRC has approximately $35 million drawn on the facility at emergence, net of unrestricted cash of approximately $72 million and $118 million used to cash collateralize on an interim basis certain letters of credit that were outstanding under CRC’s senior debtor-in-possession credit facility at the time of our emergence. We expect these letters of credit will be transitioned to our new Revolving Credit Facility and will no longer need to be cash collateralized. We believe that our new Revolving Credit Facility provides CRC with ample liquidity for our operations.

Upon emergence from Chapter 11 bankruptcy on October 27th, 2020, seven new directors were appointed to the Board of Directors. Our Board of Directors currently consists of eight directors as follows: (i) our President and Chief Executive Officer, Todd A. Stevens and (ii) seven non-employee directors, including Douglas E. Brooks, Tiffany (TJ) Thom Cepak, James N. Chapman, Mark A. McFarland, Julio M. Quintana, William B. Roby and Brian Steck.

Operational Update

In the third quarter of 2020, CRC operated no drilling rigs. The San Joaquin basin produced 78,000 net BOE per day. The Los Angeles basin produced 22,000 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.

2020 Capital Budget

Given the current commodity environment, CRC continues to be disciplined with its capital investment and will hold its internally funded capital program to a level that maintains the mechanical integrity of its facilities to continue to operate them in a safe and environmentally responsible manner.

Sustainability Update

CRC remains committed to transparent reporting of our environmental, social and governance (ESG) data which enhances our stakeholder engagement, strengthens our performance, and further supports our role as a dependable and dedicated energy producer in the State of California. Accordingly, we have continued to expand our sustainability disclosures, and have published our third annual Sustainability Report on our website covering our accomplishments in 2019. CRC’s 2030 Sustainability Goals and our ongoing sustainability strategy align with the climate goals of California, a signatory to the Paris Climate Accord, and support the state's sustainable development by providing safe, affordable and reliable energy that is essential for Californians. In addition, our new Board of Directors has reaffirmed the Sustainability – Health, Safety, Environment and Community Committee as a standing committee of the Board.

Hedging Update as of October 31, 2020

For the fourth quarter of 2020, CRC has protected the downside risk of approximately 39% of its volume of third quarter oil production, with approximately 74% of the hedges being in put spreads and put collars at an average Brent price of $44.84 and the remainder in swaps at an average Brent price of $44.75. For the first quarter of 2021, CRC has protected the downside risk of approximately 38% of its third quarter oil production, with approximately 75% of the hedges being in put spreads and put collars at an average Brent price of $45.00 and the remainder in swaps at an average Brent price of $44.75. For the second quarter of 2021, CRC has protected the downside risk of approximately 23% of its third quarter oil production, with approximately 60% of the hedges being in put spreads and put collars at an average Brent price of $40.00 and the remainder in swaps at an average Brent price of $44.75. For July 2021, CRC has protected the downside risk of approximately 22% of its third quarter oil production, with approximately 60% of the hedges being in put spreads and put collars at an average Brent price of $40.00 and the remainder in swaps at an average Brent price of $44.75.

Conference Call Details

To participate in the conference call scheduled for November 5th, 2020 at 5:00 P.M. Eastern Standard Time, either dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com, fifteen minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at http://dpregister.com/10140527. 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.

About California Resources Corporation

California Resources Corporation (CRC) is the largest oil and natural gas exploration and production company in California. CRC operates its world-class resource base exclusively within the State of California, applying complementary and integrated infrastructure to gather, process and market its production. Using advanced technology, CRC focuses on safely and responsibly supplying affordable energy for California by Californians.

Forward-Looking Statements

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

• financial position, liquidity, cash flows and results of operations
• business prospects
• transactions and projects
• operating costs
• Value Creation Index (VCI) metrics, which are based on certain estimates including future production rates, costs and commodity prices
• 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 we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:

• our ability to execute our business plan post-emergence
• the volatility of commodity prices and the potential for sustained low oil, natural gas and NGL prices
• impact of our recent emergence from bankruptcy on our business and relationships
• debt limitations on our financial flexibility
• insufficient cash flow to fund planned investments or changes to our capital plan
• insufficient capital or liquidity, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors
• limitations on transportation or storage capacity and the need to shut-in wells
• inability to enter into desirable transactions, including acquisitions, asset sales and joint ventures
• our ability to utilize our net operating loss carryforwards to reduce our income tax obligations
• limitations on the liquidity of our new common stock and volatility of its market price
• 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 or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products
• joint ventures and acquisitions and our ability to achieve expected synergies
• the recoverability of resources and unexpected geologic conditions
• incorrect estimates of reserves and related future cash flows and the inability to replace reserves
• changes in business strategy
• PSC effects on production and unit production costs
• effect of 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 coronavirus disease (COVID-19)
• factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K and third quarter 2020 Form 10-Q 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
(DEBTOR-IN-POSSESSION: Entity Operating Under Chapter 11)
		Third Quarter								Nine Months
($ and shares in millions, except per share amounts)		2020				2019				2020				2019
Statements of Operations:
Revenues
Oil and natural gas sales		$	312			$	541			$	987			$	1,720
Net derivative gain (loss) from commodity contracts		—				37				75				(31		)
Other revenue
Marketing and trading revenue		50				62				109				230
Electricity sales		43				38				75				88
Other		4				3				12				17
Total revenues		409				681				1,258				2,024
Costs and Other
Production costs		141				221				460				684
General and administrative expenses		64				66				193				228
Depreciation, depletion and amortization		89				118				296				357
Asset impairments		—				—				1,736				—
Taxes other than on income		42				42				121				119
Exploration expense		2				5				9				25
Other expenses, net
Marketing and trading costs		35				45				67				170
Electricity cost of sales		17				18				47				51
Transportation costs		10				10				31				30
Other		22				8				75				33
Total costs and other		422				533				3,035				1,697
Operating (loss) income		(13		)		148				(1,777		)		327
Non-Operating (Loss) Income
Reorganization items, net		66				—				66				—
Interest and debt expense, net		(28		)		(95		)		(200		)		(293		)
Net gain on early extinguishment of debt		—				82				5				108
Gain on asset divestitures		—				—				—				—
Other non-operating expenses		(32		)		(8		)		(93		)		(18		)
(Loss) Income Before Income Taxes		(7		)		127				(1,999		)		124
Income tax provision		—				—				—
Net (Loss) Income		(7		)		127				(1,999		)		124
Net income attributable to noncontrolling interests		(22		)		(33		)		(97		)		(85		)
Net (Loss) Income Attributable to Common Stock		$	(29	)		$	94			$	(2,096	)		$	39
Net income (loss) attributable to common stock per share - basic 1		$	2.20			$	1.89			$	(39.64	)		$	0.78
Net income (loss) attributable to common stock per share - diluted 1		$	2.20			$	1.89			$	(39.64	)		$	0.77
Adjusted net (loss) income		$	(55	)		$	17			$	(265	)		$	34
Adjusted net income (loss) per share - basic 1		$	1.68			$	0.35			$	(2.57	)		$	0.70
Adjusted net income (loss) per share - diluted 1		$	1.68			$	0.35			$	(2.57	)		$	0.69
Weighted-average common shares outstanding - basic		49.5				49.1				49.4				48.9
Weighted-average common shares outstanding - diluted		49.5				49.2				49.4				49.2
Adjusted EBITDAX		$	103			$	278			$	373			$	834
Effective tax rate		0		%		0		%		0				0		%
1 Net income (loss) and adjusted net income (loss) per diluted share for the three and nine months ended September 30, 2020 include $138 million related to the deemed redemption of the noncontrolling interest in the Ares JV.

		Third Quarter										Nine Months
($ in millions)		2020					2019					2020					2019
Cash Flow Data:
Net cash provided by operating activities		$	48				$	268				$	141				$	540
Net cash used in investing activities		$	(1	)			$	(121	)			$	(28	)			$	(291	)
Net cash used in financing activities		$	(51	)			$	(152	)			$	(8	)			$	(244	)

		September 30,					December 31,
($ and shares in millions)		2020					2019
Selected Balance Sheet Data:
Total current assets		$	420				$	491
Property, plant and equipment, net		$	4,360				$	6,352
Total current liabilities		$	1,194				$	709
Long-term debt		$	—				$	4,877
Deferred gain and issuance costs, net		$	—				$	146
Other long-term liabilities		$	727				$	720
Liabilities subject to compromise		$	4,516				$	—
Mezzanine equity		$	692				$	802
Equity		$	(2,273	)			$	(296	)
Outstanding shares		49.5					49.2

STOCK-BASED COMPENSATION
Our consolidated results of operations for the three and nine months ended September 30, 2020 and 2019 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include stock options, restricted stock units and performance stock units that either cliff vest at the end of a three-year period or vest ratably over a three year period, some of which are partially settled in cash. Our equity-settled awards granted to non-employee directors are restricted stock grants that either vest immediately or restricted stock units that cliff vest after one year. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period. Changes in our stock price introduce volatility in our results of operations because we pay cash-settled awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Cash-settled awards, including executive awards partially settled in cash, account for almost 60% of our total outstanding awards. Equity-settled awards are not similarly adjusted for changes in our stock price. Stock-based compensation is included in both general and administrative expenses and production costs as shown in the table below:
		Third Quarter										Nine Months
($ in millions, except per BOE amounts)		2020					2019					2020					2019
General and administrative expenses (G&A)
Cash-settled awards		$	(1	)			$	(2	)			$	(3	)			$	11
Equity-settled awards		2					3					6					10
Total in G&A		$	1				$	1				$	3				$	21
Total in G&A per Boe		$	0.10				$	0.09				$	0.10				$	0.59
Production costs
Cash-settled awards		$	—				$	—				$	—				$	4
Equity-settled awards		—					1					—					3
Total in production costs		$	—				$	1				$	—				$	7
Total in production costs per Boe		$	—				$	0.09				$	—				$	0.20
Total stock-based compensation expense		$	1				$	2				$	3				$	28
Total stock-based compensation expense per Boe		$	0.10				$	0.18				$	0.10				$	0.79

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS
		Third Quarter										Nine Months
($ millions)		2020					2019					2020					2019
Non-cash derivative gain (loss) - excluding noncontrolling interest		$	4				$	(6	)			$	(31	)			$	(99	)
Non-cash derivative (loss) gain - noncontrolling interest		(6		)			3					1					—
Total non-cash changes		(2		)			(3		)			(30		)			(99		)
Net proceeds on settled commodity derivatives		2					40					42					68
Net proceeds on derivative sales prior to maturity		—					$	—				63
Net derivative gain (loss) from commodity contracts		$	—				$	37				$	75				$	(31	)

Attachment 2
PRODUCTION STATISTICS
		Third Quarter						Nine Months
Net Oil, NGLs and Natural Gas Production Per Day		2020			2019			2020			2019
Oil (MBbl/d)
San Joaquin Basin		40			51			42			53
Los Angeles Basin		22			24			25			24
Ventura Basin		2			4			3			4
Total		64			79			70			81
NGLs (MBbl/d)
San Joaquin Basin		14			16			14			15
Ventura Basin		—			—			—			1
Total		14			16			14			16
Natural Gas (MMcf/d)
San Joaquin Basin		142			162			148			163
Los Angeles Basin		2			2			2			2
Ventura Basin		4			4			4			6
Sacramento Basin		20			28			21			29
Total		168			196			175			200
Total Production (MBoe/d)		106			128			113			130
		Third Quarter						Nine Months
Gross Operated and Net Non-Operated Oil, NGLs and Natural Gas Production Per Day		2020			2019			2020			2019
Oil (MBbl/d)
San Joaquin Basin		46			55			49			56
Los Angeles Basin		28			32			30			33
Ventura Basin		3			5			3			5
Total		77			92			82			94
NGLs (MBbl/d)
San Joaquin Basin		14			16			14			15
Ventura Basin		—			—			—			1
Total		14			16			14			16
Natural Gas (MMcf/d)
San Joaquin Basin		153			164			157			165
Los Angeles Basin		8			9			9			9
Ventura Basin		4			4			5			6
Sacramento Basin		25			38			27			39
Total		190			215			198			219
Total Production (MBoe/d)		123			144			130			146

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 historic cost of depreciable and depletable 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 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 per diluted share.
		Third Quarter										Nine Months
($ millions, except per share amounts)		2020					2019					2020					2019
Net (loss) income		$	(7	)			$	127				$	(1,999	)			$	124
Net income attributable to noncontrolling interests		(22		)			(33		)			(97		)			(85		)
Net (loss) income attributable to common stock		(29		)			94					(2,096		)			39
Unusual, infrequent and other items:
Non-cash derivative (gain) loss from commodities, excluding noncontrolling interest		(4		)			6					31					99
Asset impairments		—					—					1,736					—
Reorganization items, net		(66		)			—					(66		)			—
Severance and termination benefits		10					—					10					2
Incentive / retention award modifications		—					—					4					—
Net gain on early extinguishment of debt		—					(82		)			(5		)			(108		)
Chapter 11 transaction costs		15					—					64					—
NGL pipeline delivery contract payment		—					—					20					—
Power plant maintenance		—					—					7					—
Write-off of deferred financing costs		4					—					4
Other, net		15					(1		)			26					2
Total unusual, infrequent and other items		(26		)			(77		)			1,831					(5		)
Adjusted net (loss) income		$	(55	)			$	17				$	(265	)			$	34
Net income (loss) attributable to common stock per share - diluted 1		$	2.20				$	1.89				$	(39.64	)			$	0.77
Adjusted net income (loss) per share - diluted 1		$	1.68				$	0.35				$	(2.57	)			$	0.69
1 Net income (loss) and adjusted net income (loss) per diluted share for the three and nine months ended September 30, 2020 include $138 million related to the deemed redemption of the noncontrolling interest in the Ares JV.

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.
		Third Quarter										Nine Months
($ millions)		2020					2019					2020					2019
Net cash provided by operating activities		$	48				$	268				$	141				$	540
Capital investments		(4		)			(122		)			(37		)			(393		)
Free cash flow		44					146					104					147
BSP funded capital		—					5					—					48
Free cash flow, after internally funded capital		$	44				$	151				$	104				$	195

ADJUSTED EBITDAX
We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items; and other non-cash items. Management uses adjusted EBITDAX as a measure of operating cash flow without working capital adjustments. A version of adjusted EBITDAX is a material component of certain of our financial covenants under our 2014 Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX.
		Third Quarter										Nine Months
($ millions, except per BOE amounts)		2020					2019					2020					2019
Net (loss) income		$	(7	)			$	127				$	(1,999	)			$	124
Interest and debt expense, net		28					95					200					293
Depreciation, depletion and amortization		89					118					296					357
Exploration expense		2					5					9					25
Unusual, infrequent and other items (a)		(26		)			(77		)			1,831					(5		)
Other non-cash items		17					10					36					40
Adjusted EBITDAX		$	103				$	278				$	373				$	834
Net cash provided by operating activities		$	48				$	268				$	141				$	540
Cash interest		21					75					80					300
Exploration expenditures		2					5					9					15
Working capital changes		32					(70		)			143					(21		)
Adjusted EBITDAX		$	103				$	278				$	373				$	834
Adjusted EBITDAX per Boe		$	10.61				$	23.68				$	12.04				$	23.55
(a) See Adjusted Net Income 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.
		Third Quarter										Nine Months
($ millions)		2020					2019					2020					2019
Adjusted EBITDAX		$	103				$	278				$	373				$	834
Cash interest		(21		)			(75		)			(80		)			(300		)
Distributions paid to noncontrolling interest holders:
BSP		(5		)			(30		)			(34		)			(55		)
Ares		(22		)			(20		)			(61		)			(60		)
Discretionary cash flow		$	55				$	153				$	198				$	419

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.
		Third Quarter								Nine Months
($ millions)		2020				2019				2020				2019
Total revenues		$	409			$	681			$	1,258			$	2,024
Non-cash derivative loss		2				3				30				99
Revenues, excluding non-cash derivative gains and losses		$	411			$	684			$	1,288			$	2,123
Adjusted EBITDAX margin		25		%		41		%		29		%		39		%

PRODUCTION COSTS PER BOE
The reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. The following table presents production costs after adjusting for the excess costs attributable to PSC-type contracts.
		Third Quarter										Nine Months
($ per Boe)		2020					2019					2020					2019
Production costs		$	14.52				$	18.82				$	14.85				$	19.32
Excess costs attributable to PSC-type contracts		(1.15		)			(1.38		)			(0.82		)			(1.50		)
Production costs, excluding effects of PSC-type contracts		$	13.37				$	17.44				$	14.03				$	17.82

Attachment 4
CAPITAL INVESTMENTS
		Third Quarter									Nine Months
($ millions)		2020					2019				2020				2019
Internally funded capital		$	4				$	117			$	37			$	345
BSP funded capital		—					5				—				48
Capital investments - as reported		$	4				$	122			$	37			$	393
MIRA funded capital		—					3				1				10
Alpine funded capital		(4		)			63				93				63
Total capital program		$	—				$	188			$	131			$	466

														Attachment 5
PRICE STATISTICS
		Third Quarter								Nine Months
		2020				2019				2020				2019
Realized Prices
Oil with hedge ($/Bbl)		$	42.15			$	68.41			$	43.27			$	68.16
Oil without hedge ($/Bbl)		$	41.83			$	62.85			$	41.27			$	65.03
NGLs ($/Bbl)		$	25.16			$	23.55			$	25.17			$	31.04
Natural gas ($/Mcf)		$	2.22			$	2.73			$	2.05			$	2.82
Index Prices
Brent oil ($/Bbl)		$	43.37			$	62.00			$	42.53			$	64.74
WTI oil ($/Bbl)		$	40.93			$	56.45			$	38.32			$	57.06
NYMEX gas ($/MMBtu)		$	1.93			$	2.27			$	1.92			$	2.72
Realized Prices as Percentage of Index Prices
Oil with hedge as a percentage of Brent		97		%		110		%		102		%		105		%
Oil without hedge as a percentage of Brent		96		%		101		%		97		%		100		%
Oil with hedge as a percentage of WTI		103		%		121		%		113		%		119		%
Oil without hedge as a percentage of WTI		102		%		111		%		108		%		114		%
NGLs as a percentage of Brent		58		%		38		%		59		%		48		%
NGLs as a percentage of WTI		61		%		42		%		66		%		54		%
Natural gas as a percentage of NYMEX		115		%		120		%		107		%		104		%

Attachment 6
NINE MONTHS 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 (a)		68		4		—		—		72
		San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled		Basin		Basin		Basin		Basin		Total
CRC		3		4		—		—		7
Alpine		65		—		—		—		65
Total (a)		68		4		—		—		72
There were no wells drilled in the third quarter of 2020.
(a) 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 OCTOBER 31, 2020
		Q4 2020			Q1 2021		Q2 2021		July 2021
Sold Calls:
Barrels per day		4,800			4,500		4,500		4,200
Weighted-average price per barrel		$48.05			$48.05		$48.05		$48.05
Purchased Puts:
Barrels per day		18,600			18,000		9,000		8,400
Weighted-average price per barrel		$44.84			$45.00		$40.00		$40.00
Sold Puts:
Barrels per day		13,800			13,500		4,500		4,200
Weighted-average price per barrel		$36.52			$36.67		$30.00		$30.00
Swaps:
Barrels per day		6,400			6,000		6,000		5,600
Weighted-average price per barrel		$44.75			$44.75		$44.75		$44.75
The outcomes of the derivative positions are as follows:
Sold calls - we make settlement payments for prices above the indicated weighted-average price per barrel
Purchased puts - we receive settlement payments for prices below the indicated weighted-average price per barrel
Sold puts - we make settlement payments for prices below the indicated weighted-average price per barrel
The BSP JV holds crude oil derivatives and natural gas swaps for insignificant volumes through 2021 that are included in our consolidated results. The hedges entered into by the BSP JV could affect the timing of the redemption of BSP's preferred interest.

Attachment 8
EARNINGS PER SHARE
		Three Months Ended											Nine Months Ended
		September 30,											September 30
In millions, except per-share amounts		2020						2019					2020					2019
Basic EPS calculation
Net (loss) income		$	(7	)				$	127				$	(1,999	)			$	124
Less: net income attributable to noncontrolling interests		(22		)				(33		)			(97		)			(85		)
Net (loss) income attributable to common stock		(29		)				94					(2,096		)			39
Adjustments:
Net income allocated to participating securities		—						(1		)			—					(1		)
Return from noncontrolling interest holders (a)		138						—					138					—
Net income (loss) available to common shares		109						93					(1,958		)			38
Weighted-average common shares outstanding - basic		49.5						49.1					49.4					48.9
Basic EPS		$	2.20					$	1.89				$	(39.64	)			$	0.78
Diluted EPS calculation
Net (loss) income		$	(7	)				$	127				$	(1,999	)			$	124
Less: net income attributable to noncontrolling interests		(22		)				(33		)			(97		)			(85		)
Net (loss) income attributable to common stock		(29		)				94					(2,096		)			39
Adjustments:
Net income allocated to participating securities		—						(1		)			—					(1		)
Return from noncontrolling interest holders (a)		138						—					138					—
Net income (loss) available to common shares		109						93					(1,958		)			38
Weighted-average common shares outstanding - basic		49.5						49.1					49.4					48.9
Dilutive effect of potentially dilutive securities		—						0.1					—					0.3
Weighted-average common shares outstanding - diluted		49.5						49.2					49.4					49.2
Diluted EPS		$	2.20					$	1.89				$	(39.64	)			$	0.77
Weighted-average anti-dilutive shares		3.3						3.2					4.4					2.3
(a) Return from noncontrolling interest holders relates to the deemed redemption of the noncontrolling interests in the Ares JV.