California Resources Corporation Reports Second Quarter 2021 Results, Increases Free Cash Flow Guidance, Raises Share Repurchase Program to $250 Million and Announces Strategic A&D Transactions

Rhea-AI Summary

California Resources Corporation (CRC) reported strong second quarter results, increasing its 2021 free cash flow guidance to $400-$500 million. The company raised its Share Repurchase Program from $150 million to $250 million and announced an acquisition of a 90% working interest in joint venture wells for $53 million. CRC also plans to divest non-core Ventura operations, projected to generate up to $102 million in cash. The company is advancing its CCS initiatives, targeting a 40 million metric ton permanent storage project, reinforcing its commitment to energy transition.

Positive

• Increased 2021 free cash flow guidance to $400-$500 million from $250-$350 million.
• Raised Share Repurchase Program from $150 million to $250 million, enhancing shareholder value.
• Acquisition of a 90% working interest in joint venture wells for $53 million expected to boost production.
• Planned divestiture of non-core Ventura operations projected to generate up to $102 million.

Negative

• Reported a net loss attributable to common stock of $111 million, or $1.34 per diluted share.
• Production volumes decreased 10% year-over-year, from 112,000 BOE per day to 101,000 BOE per day.
• Sustained operating costs increased due to higher energy costs and deferred activities from 2020.

California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today reported second quarter 2021 operational and financial results.

“CRC continued to deliver on its strategy with strong second quarter results driven by robust financial and operational performance, resulting in an increase in 2021 free cash flow¹ guidance to $400 to $500 million. Given our financial strength and low stock valuation relative to fundamentals, we are increasing our Share Repurchase Program from $150 million to $250 million," said Mac McFarland, President and Chief Executive Officer. "I am also pleased to announce an acquisition of the 90% working interest in the joint venture wells held by our partner as well as a planned divestiture of our non-core Ventura operations. These strategic A&D transactions will simplify our business model, lower our overall operating costs and provide positive net cash proceeds."

Mr. McFarland continued, "We continued to make strides on our ESG strategy and are pleased to announce we have identified approximately one billion metric tons of CO₂ permanent storage capacity as well as up to 1,000 megawatts (MW) of front-of-the-meter solar opportunities which will help contribute to the decarbonization of California. As a first step, we are submitting permits for an ~40 million metric ton permanent storage CCS project, Carbon TerraVault I. Further, we are advancing arrangements with SunPower for an initial 12 MW and up to 45 MW of behind-the-meter solar projects.

"I'm also excited to announce the appointment of Nicole Neeman Brady to our Board and look forward to her contributions, particularly on the Sustainability Committee."

Second Quarter 2021 Highlights

Financial

• Reported a net loss attributable to common stock of $111 million, or $1.34 per diluted share. Adjusted net income¹ was $78 million, or $0.94 per diluted share
• Generated net cash provided by operating activities of $127 million, adjusted EBITDAX¹ of $169 million and free cash flow¹ of $77 million
• Closed the quarter with $151 million of cash on hand, an undrawn credit facility and $518 million of liquidity²
• Sustained non-energy operating costs and general and administrative (G&A) expense improvements achieved earlier in 2021

Operational

• Produced an average of 101,000 net barrels of oil equivalent (BOE) per day, including 61,000 barrels per day of oil, with quarterly capital expenditures of $50 million
• Operated two drilling rigs in the San Joaquin Basin and drilled 21 wells (21 online in 2Q21)
• Operated 35 maintenance rigs
• Completed 48 capital workovers

Transactional

• Signed agreements to divest operations in the Ventura basin for total cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices
• Post quarter end, acquired the working interest in the joint venture wells held by Macquarie Infrastructure and Real Assets, Inc. (“MIRA”) for $53 million
• Post quarter end, filing permits for an ~40 MMT CO₂ permanent storage CCS project, Carbon TerraVault I
• Advancing a 12 MW behind-the-meter solar project with SunPower for CRC's Mt. Poso field which is expected to be Low Carbon Fuel Standard ("LCFS") eligible; construction is expected to begin in early 2022

Guidance

• Raised 2021 free cash flow¹ guidance to $400 to $500 million
• Optimized CRC investment dollars by shifting an additional $20 million from drilling and completions to downhole maintenance projects which provide efficiencies and faster payouts
• Raised the Share Repurchase Program ("SRP") to $250 million from $150 million; repurchased 1.4 million shares for $45 million in 2Q21

2021 Guidance & Capital Program

Given the strength of the second quarter results, CRC has raised its full year 2021 free cash flow¹ guidance to $400 to $500 million from $250 to $350 million, adjusted EBITDAX¹ guidance to $725 to $825 million from $625 to $725 million and production guidance to 97 to 100 MBOE per day from 96 to 99 MBOE per day. Recognizing capital efficiency improvements and faster payouts on downhole maintenance projects, CRC revised its full year 2021 operating cost and capital guidance by shifting an additional $20 million of drilling capital to these opportunities. In addition to this shift from capital to operating costs, an increase in natural gas prices further raises expected operating costs by approximately $35 million, which is more than offset by increased natural gas revenues as CRC is net long natural gas on the whole. These two items result in revised full year 2021 capital guidance of $170 to $190 million from $185 to $210 million and revised full year 2021 operating cost guidance of $670 to $695 million from $615 to $630 million.

CRC made $77 million of capital investments in the first half of 2021. The current capital program anticipates that CRC will maintain a consistent level of investment throughout the remainder of the year. If commodity prices decline significantly from current levels. CRC may need to decrease the size of its capital program in response to market conditions. The Company's capital program will be dynamic in response to oil market volatility while focusing on maintaining its oil production, strong liquidity and maximizing its free cash flow.

		Prior		Revised
2021E TOTAL YEAR GUIDANCE		Total Year 2021E		Total Year 2021E
Total Production (Mboe/d)		96 - 99		97 - 100
Oil Production (Mbbl/d)		60 - 62		60 - 62
Operating Costs ($ millions)		$615 - $630		$670 - $695
General and administrative expenses ($ millions)		$180 - $190		$180 - $190
Capital ($ millions)		$185 - $210		$170 - $190
Adj. EBITDAX1 ($ millions)		$625 - $725		$725 - $825
Free cash flow1 ($ millions)		$250 - $350		$400 - $500

Increasing the Share Repurchase Program

In August 2021, CRC's Board of Directors increased the Share Repurchase Program by $100 million to $250 million through March 31, 2022.

Acquisitions and Divestitures

In the second quarter of 2021, CRC entered into agreements to sell its Ventura basin operations for expected cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices. The consideration includes $82 million of cash to be paid at closing and up to $20 million of potential additional consideration if the buyer does not perform certain abandonment obligations with respect to the divested properties. These transactions will simplify CRC's business model, lower its overall operating costs and decrease its asset retirement obligations. For the three months ending June 30, 2021, CRC's Ventura basin operations were producing 3,600 BOE per day (~65% oil). The closing of the transaction is subject to customary closing conditions, including satisfaction of land and environmental due diligence and third-party consents.

In August 2021, CRC continued to demonstrate its focus on core areas by acquiring the 90% working interest in the joint venture wells held by MIRA for $53 million, before transaction costs. The acquisition of MIRA’s working interest would have added oil production of 1,600 BOE per day (~100% oil) for the first half of 2021 with minimal integration costs and underground risk.

CRC’s full year guidance will be updated upon the closing of the Ventura basin transactions which are expected in the second half of 2021.

Sustainability Update

According to internal and third party estimates, CRC has some of the lowest carbon intensity production in the U.S. CRC aims to build upon this position through investment in decarbonization projects and other emissions reducing projects to help advance energy transition in California. As part of an initial review, CRC has the potential to permanently store up to 1 billion metric tons of CO₂ in its oil and gas reservoirs as well as the opportunity to generate 300 to 1,000 MW of front-of-the-meter solar power for the grid by utilizing CRC's vast surface land footprint. In addition to these opportunities, CRC has the potential for up to 45 MW of behind-the-meter solar development projects with its partner SunPower.

Building on CRC's carbon capture opportunity, CRC is applying for Class VI EPA permits for a project with a capability of up to 40 million metric tons of permanent CO₂ storage, referred to as Carbon TerraVault I. Injection for this project could begin in the 2025 time frame with the injection of approximately 1 million metric tons per year, equivalent to the annual emissions of approximately 200,000 passenger vehicles. CRC is proud to be a first mover of CCS operations in California and to help the state make progress on its carbon neutrality goals.

CRC has a dedicated Sustainability Committee chaired by William B. Roby, with members Nicole Neeman Brady and Andrew B. Bremner along with a dedicated corporate function under the executive leadership of Chris Gould as EVP and Chief Sustainability Officer.

Board Enhancement

On August 5, 2021, CRC's Board of Directors elected one new Board member, Nicole Neeman Brady.

Ms. Neeman Brady has over 20 years of experience as an entrepreneur, executive, investor and community leader with global water, energy, and agricultural expertise. She serves as the Chief Executive Officer and a director of Sustainable Development Acquisition Corp. since December 2020. She also served as Principal and Chief Operating Officer at Renewable Resources Group LLC, as well as a member of the Investment Committee and a board member of several of its portfolio companies. Her experience also includes a deep understanding of and passion for the public sector, including board service on the Colorado River Board of California and currently, as a Commissioner on the Los Angeles Department of Water and Power, a Board member of Blue Ocean Mariculture and a Board member of the Library Foundation of Los Angeles. Please see www.crc.com for more details.

Fresh Start Accounting and Predecessor and Successor Periods

CRC qualified and adopted fresh start accounting upon emergence from bankruptcy on October 27, 2020, at which point CRC became a new entity for financial reporting purposes. CRC adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of the joint plan of reorganization, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

Second Quarter 2021 Results

		Successor					Predecessor
		2nd Quarter					2nd Quarter
($ and shares in millions, except per share amounts)		2021					2020
Statements of Operations:
Revenues
Total revenues		$	304				$	276
Costs
Total costs		394					391
Operating Loss		$	(90	)			$	(115	)
Net Loss Attributable to Common Stock		$	(111	)			$	(271	)
Net loss attributable to common stock per share - basic and diluted		$	(1.34	)			$	(5.47	)
Adjusted net income (loss)		$	78				$	(202	)
Adjusted net income (loss) per share - basic		$	0.94				$	(4.08	)
Weighted-average common shares outstanding - basic		83.1					49.5
Adjusted EBITDAX		$	169				$	19

		Successor					Predecessor
		2nd Quarter					2nd Quarter
($ in millions)		2021					2020
Cash Flow Data:
Net cash provided by operating activities		$	127				$	(135	)
Net cash used in investing activities		$	(43	)			$	(15	)
Net cash (used in) provided by financing activities		$	(63	)			$	199

Six-Month 2021 Results

		Successor					Predecessor
		Six Months					Six Months
($ and shares in millions, except per share amounts)		2021					2020
Statements of Operations:
Revenues
Total revenues		$	667				$	849
Costs
Total costs		830					2,613
Operating Loss		$	(163	)			$	(1,764	)
Net Loss Attributable to Common Stock		$	(205	)			$	(2,067	)
Net loss attributable to common stock per share - basic and diluted		$	(2.46	)			$	(41.84	)
Adjusted net income (loss)		$	180				$	(210	)
Adjusted net income (loss) per share - basic		$	2.16				$	(4.25	)
Weighted-average common shares outstanding - basic		83.2					49.4
Adjusted EBITDAX		$	358				$	270

		Successor					Predecessor
		Six Months					Six Months
($ in millions)		2021					2020
Cash Flow Data:
Net cash provided by operating activities		$	274				$	93
Net cash used by investing activities		$	(63	)			$	(27	)
Net cash (used) provided by financing activities		$	(88	)			$	43

Review of Operating and Financial Results

Total daily net production volumes decreased 10% from 112,000 BOE per day for the second quarter of 2020 to 101,000 BOE per day for the second quarter of 2021. The decrease from the same period in 2020 was primarily due to limited drilling activity and capital investment during the prior twelve months and natural decline rates. Total daily net production volumes decreased 15% from 117,000 BOE per day for the six months ended June 30, 2020 to 100,000 BOE per day for the same period in 2021. Production sharing type contracts (PSC-type) at CRC's Long Beach assets negatively impacted oil production by approximately 5,000 and 4,000 barrels per day in the three and six months ended June 30, 2021, respectively, compared to the same prior-year period. See Attachment 3 for further information on production.

Realized oil prices, including the effect of settled hedges, increased by $23.28 per barrel from $30.82 per barrel in the second quarter of 2020 to $54.10 per barrel in the second quarter of 2021. For the six months ended June 30, 2021, realized oil prices, including the effect of settled hedges, increased by $10.15 to $53.91 from $43.76 in the same period of 2020. Realized oil prices were higher in the second quarter of 2021 compared to the same prior-year period as oil demand recovered from its COVID-19 driven lows. See Attachment 4 for further information on prices.

Adjusted EBITDAX¹ for the second quarter of 2021 was $169 million and net cash provided by operating activities was $127 million. Internally funded capital invested during the second quarter of 2021 was $50 million. Free cash flow¹ was $77 million. Adjusted EBITDAX¹ for the six months ended June 30, 2021 was $358 million and net cash provided by operating activities was $274 million. For the first half of 2021, internally funded capital invested was $77 million. Free cash flow¹ was $197 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 bankruptcy related fees during 2021 and 2020 as a supplemental measure of free cash flow.
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
($ millions)		2021					2020					2021					2020
Net cash provided by operating activities		$	127				$	(135	)			$	274				$	93
Capital investments		(50		)			(3		)			(77		)			(33		)
Free cash flow		77					(138		)			197					60
One-time bankruptcy related fees		2					42					4					47
Free cash flow, after special items		$	79				$	(96	)			$	201				$	107

Operating costs for the second quarter of 2021 were $169 million compared to $127 million for the second quarter of 2020. Operating costs for the six months ended June 30, 2021 were $333 million compared to $319 million for the same period in 2020. The increase was primarily attributable to higher downhole maintenance activity in 2021 which was deferred in 2020 as CRC shut-in wells. Additionally, operating costs increased in 2021 due to higher energy costs and natural gas prices as compared to 2020. Partially offsetting these increases were lower compensation-related costs from streamlining CRC's operations, which included headcount reductions in late 2020 and early 2021. CRC's second quarter 2020 reflect cost savings for reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic. Although higher natural gas and electricity prices in 2021 increased CRC's operating costs, higher prices have a net positive effect on operating results due to higher revenue from sales of these commodities which CRC also produces.

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.
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
($ per Boe)		2021					2020					2021					2020
Energy operating costs (a)		$	4.70				$	3.51				$	4.70				$	3.61
Gas processing costs		0.66					0.46					0.60					$	0.57
Non-energy operating costs (b)		13.12					8.45					13.10					10.81
Operating costs		$	18.48				$	12.42				$	18.40				$	14.99
Excess costs attributable to PSC-type contracts		(1.73		)			(0.42		)			(1.66		)			(0.66		)
Operating costs, excluding effects of PSC-type contracts		$	16.75				$	12.00				$	16.74				$	14.33

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

(b) Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchases of fuel gas to generate steam which is then used in our steamfloods is included in non-energy operating costs.

G&A expenses were $48 million for the second quarter of 2021, compared to $69 million in the same prior-year period. For the six months ended June 30, 2021, G&A expenses were $96 million compared to $129 million in the same prior-year period. The decrease in G&A expenses reflects lower compensation-related costs primarily due to workforce reductions that occurred in the second half of 2020 and the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. CRC's second quarter 2020 results include savings from reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic. The remaining decrease between comparative periods was primarily due to cost saving efforts which resulted in lower spend across a number of cost categories. The decrease was partially offset by stock-based compensation expense related to awards granted to executives and directors in 2021.

Balance Sheet and Liquidity Update

CRC's aggregate commitment under the Revolving Credit Facility was $492 million as of June 30, 2021. The borrowing base for the Revolving Credit Facility is redetermined around April and October of each year and was most recently set at $1.2 billion in May 2021. The amount CRC is able to borrow under the Revolving Credit Facility is limited to the amount of the commitment described above.

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

As of June 30, 2021, CRC had liquidity of $518 million, which consisted of $151 million in unrestricted cash and $367 million of available borrowing capacity under its Revolving Credit Facility after accounting for $125 million in outstanding letters of credit.

CRC anticipates the preferred interest in a development joint venture held by Benefit Street Partners ("BSP") could be automatically redeemed in the second half of 2021. We anticipate the remaining distributions to BSP will approximate $20 million.

CRC may begin paying income taxes in early 2022 if Brent prices remain at current levels for a sustained period. CRC's tax paying status depends on a number of factors, including but not limited to, the amount and type of CRC's capital spend, cost structure and activity levels. Potential legislation could also limit tax incentives for fossil fuels.

Operational Update

During the second quarter of 2021, CRC operated an average of two drilling rigs in the San Joaquin Basin, drilled 21 net wells, 19 of which were brought online in addition to the two that were brought online from the first quarter totaling 21 online wells. The San Joaquin basin produced 74,500 net BOE per day. The Los Angeles basin produced 19,200 net BOE per day, the Ventura basin produced 3,600 net BOE per day and the Sacramento basin produced 3,300 net BOE per day.

September 2021 Investor Conferences

CRC's executives will be participating in the Barclays CEO Energy-Power Conference on September 8-10. Mac McFarland, President and CEO, and Francisco Leon, EVP and CFO, will also be presenting on September 10^th at 10:55 a.m. ET.

CRC’s presentation materials will be available the day of the event on the Earnings and Presentations page in the Investor Relations section on www.crc.com.

Conference Call Details

To participate in the conference call scheduled for later today at 5:00 p.m. Eastern Time, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10157220/e9185e9690. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.

¹ See Attachment 2 for the non-GAAP financial measures of adjusted EBITDAX, operating costs per BOE (excluding effects of PSC-type contracts), adjusted net income (loss) and free cash flow, including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2021 estimates of the non-GAAP measures of adjusted EBITDAX and free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
² Calculated as $151 million of cash plus $492 million of capacity on CRC's Revolving Credit Facility less $125 million in outstanding letters of credit.

About California Resources Corporation

California Resources Corporation (CRC) is an independent oil and natural gas company committed to energy transition in the sector. CRC has some of the lowest carbon intensity production in the U.S. and we are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing Carbon Capture and Sequestration (CCS) and other emissions reducing projects. For more information about CRC, please visit www.crc.com.

Forward-Looking Statements

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

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

Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While 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 (i) drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) managing energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) protection of health, safety and the environment, (iv) tax credits or other incentives, or (v) transportation, marketing and sale of 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
• CRC's ability to recognize the benefits of business strategies and initiatives related to energy transition, including carbon capture and sequestration projects and other renewable energy efforts
• factors discussed in Item 1A, Risk Factors in 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
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
($ and shares in millions, except per share amounts)		2021					2020					2021					2020
Statements of Operations:
Revenues
Oil, natural gas and NGL sales		$	478				$	245				$	910				$	675
Net derivative (loss) gain from commodity contracts		(265		)			(4		)			(478		)			75
Other revenue
Trading revenue		48					14					146					59
Electricity sales		33					19					66					32
Other		10					2					23					8
Total revenues		304					276					667					849
Costs
Operating costs		169					127					333					319
General and administrative expenses		48					69					96					129
Depreciation, depletion and amortization		54					88					106					207
Asset impairments		—					—					3					1,736
Taxes other than on income		37					38					77					79
Exploration expense		2					2					4					7
Other expenses, net
Trading costs		30					8					91					32
Electricity cost of sales		17					14					41					30
Transportation costs		14					8					26					21
Other		23					37					53					53
Total costs		394					391					830					2,613
Operating Loss		(90		)			(115		)			(163		)			(1,764		)
Non-Operating (Loss) Income
Reorganization items, net		(2		)			—					(4		)			—
Interest and debt expense, net		(13		)			(85		)			(26		)			(172		)
Net (loss) gain on extinguishment of debt		—					—					(2		)			5
Other non-operating expenses		(2		)			(47		)			(1		)			(61		)
Loss Before Income Taxes		(107		)			(247		)			(196		)			(1,992		)
Income tax provision		—					—					—					—
Net Loss		(107		)			(247		)			(196		)			(1,992		)
Net income attributable to noncontrolling interests		(4		)			(24		)			(9		)			(75		)
Net Loss Attributable to Common Stock		$	(111	)			$	(271	)			$	(205	)			$	(2,067	)
Net loss attributable to common stock per share - basic and diluted		$	(1.34	)			$	(5.47	)			$	(2.46	)			$	(41.84	)
Adjusted net income (loss)		$	78				$	(202	)			$	180				$	(210	)
Adjusted net income (loss) per share - basic		$	0.94				$	(4.08	)			$	2.16				$	(4.25	)
Adjusted net income (loss) per share - diluted		$	0.94				$	(4.08	)			$	2.15				$	(4.25	)
Weighted-average common shares outstanding - basic		83.1					49.5					83.2					49.4
Weighted-average common shares outstanding - diluted		83.4					49.5					83.7					49.4
Adjusted EBITDAX		$	169				$	19				$	358				$	270
Effective tax rate		0		%			0		%			0		%			0		%

		Successor					Predecessor					Successor					Predecessor
		2nd Qtr.					2nd Qtr.					Six Months					Six Months
($ in millions)		2021					2020					2021					2020
Cash Flow Data:
Net cash provided (used) by operating activities		$	127				$	(135	)			$	274				$	93
Net cash used by investing activities		$	(43	)			$	(15	)			$	(63	)			$	(27	)
Net cash (used) provided by financing activities		$	(63	)			$	199				$	(88	)			$	43

		June 30,				December 31,
($ and shares in millions)		2021				2020
Selected Balance Sheet Data:
Total current assets		$	577			$	329
Property, plant and equipment, net		$	2,573			$	2,655
Total current liabilities		$	886			$	473
Long-term debt, net		$	589			$	597
Other long-term liabilities		$	850			$	822
Stockholder's Equity		$	915			$	1,182
Outstanding shares		81.9				83.3

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS
		Successor					Predecessor					Successor					Predecessor
		2nd Qtr.					2nd Qtr.					Six Months					Six Months
($ millions)		2021					2020					2021					2020
Non-cash derivative loss - excluding noncontrolling interest		$	(183	)			$	—				$	(357	)			$	(35	)
Non-cash derivative (loss) gain - noncontrolling interest		—					(9		)			—					7
Total non-cash changes		(183		)			(9		)			(357		)			(28		)
Net (payments) proceeds on settled commodity derivatives		(82		)			5					(121		)			40
Net proceeds on sale of commodity derivatives		—					—					—					63
Net derivative (loss) gain from commodity contracts		$	(265	)			$	(4	)			$	(478	)			$	75

CAPITAL INVESTMENTS
		Successor				Predecessor					Successor				Predecessor
		2nd Qtr.				2nd Qtr.					Six Months				Six Months
($ millions)		2021				2020					2021				2020
Internally funded capital		$	50			$	3				$	77			$	33
Capital investments not included on our financial statements:
MIRA funded capital		—				(1		)			—				1
Alpine funded capital		—				8					—				97
Total capital program		$	50			$	10				$	77			$	131

Attachment 2

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

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

ADJUSTED NET INCOME (LOSS)
Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. We define adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing our financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income (loss) and net income (loss) attributable to common stock per share to the non-GAAP financial measure of adjusted net income (loss) and adjusted net income (loss) per share.
		Successor					Predecessor					Successor					Predecessor
		2nd Qtr.					2nd Qtr.					Six Months					Six Months
($ millions, except per share amounts)		2021					2020					2021					2020
Net loss		$	(107	)			$	(247	)			$	(196	)			$	(1,992	)
Net income attributable to noncontrolling interests		(4		)			(24		)			(9		)			(75		)
Net loss attributable to common stock		(111		)			(271		)			(205		)			(2,067		)
Unusual, infrequent and other items:
Non-cash derivative loss from commodities, excluding noncontrolling interest		183					—					357					35
Asset impairments		—					—					3					1,736
Reorganization items, net		2					—					4					—
Chapter 11 transaction costs		—					49					—					49
Severance and termination costs		1					—					15					—
Net loss (gain) on extinguishment of debt		—					—					2					(5		)
Deficiency payment on pipeline delivery contract		—					20					—					20
Power plant maintenance		—					—					—					7
Incentive and retention award modification		—					4					—					4
Gains on asset divestitures		—					—					(2		)
Rig termination expenses		1					2					2					2
Other, net		2					(6		)			4					9
Total unusual, infrequent and other items		189					69					385					1,857
Adjusted net income (loss) attributable to common stock		$	78				$	(202	)			$	180				$	(210	)
Net loss attributable to common stock per share - diluted		$	(1.34	)			$	(5.47	)			$	(2.46	)			$	(41.84	)
Adjusted net income (loss) per share - basic		$	0.94				$	(4.08	)			$	2.16				$	(4.25	)
Adjusted net income (loss) per share - diluted		$	0.94				$	(4.08	)			$	2.15				$	(4.25	)

FREE CASH FLOW
Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We have excluded one-time costs for bankruptcy related fees during 2021 and 2020 as a supplemental measure of our free cash flow.
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
($ millions)		2021					2020					2021					2020
Net cash provided (used) by operating activities		$	127				$	(135	)			$	274				$	93
Capital investments		(50		)			(3		)			(77		)			(33		)
Free cash flow		77					(138		)			197					60
One-time bankruptcy related fees		2					42					4					47
Free cash flow, after special items		$	79				$	(96	)			$	201				$	107

ADJUSTED EBITDAX
We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as depreciation, depletion and amortization of our assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of our financial covenants under our Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.
		Successor					Predecessor					Successor					Predecessor
		2nd Qtr.					2nd Qtr.					Six Months					Six Months
($ millions, except per BOE amounts)		2021					2020					2021					2020
Net loss		$	(107	)			$	(247	)			$	(196	)			$	(1,992	)
Interest and debt expense, net		13					85					26					172
Depreciation, depletion and amortization		54					88					106					207
Exploration expense		2					2					4					7
Unusual, infrequent and other items (a)		189					69					385					1,857
Non-cash items
Accretion expense		13					10					26					20
Stock-settled compensation		4					2					5					4
Post-retirement medical and pension		1					1					2					2
Other non-cash items		—					9					—					(7		)
Adjusted EBITDAX		$	169				$	19				$	358				$	270
Net cash provided (used) by operating activities		$	127				$	(135	)			$	274				$	93
Cash interest		2					10					5					59
Exploration expenditures		2					2					4					7
Working capital changes		38					142					75					111
Adjusted EBITDAX		$	169				$	19				$	358				$	270
Adjusted EBITDAX per Boe		$	18.48				$	1.86				$	19.78				$	12.69
(a) See Adjusted Net Income (Loss) reconciliation.

DISCRETIONARY CASH FLOW
We define discretionary cash flow as the cash available after distributions to noncontrolling interest holders and cash interest, excluding the effect of working capital changes but before our internal capital investment. Management uses discretionary cash flow as a measure of the availability of cash to reduce debt or fund investments.
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
($ millions)		2021					2020					2021					2020
Adjusted EBITDAX		$	169				$	19				$	358				$	270
Cash interest		(2		)			(10		)			(5		)			(59		)
Distributions paid to noncontrolling interest holders:
BSP		(17		)			(5		)			(31		)			(29		)
Ares		—					(19		)			—					(39		)
Asset retirement obligations and idle well testing		(12		)			(2		)			(24		)			(6		)
Discretionary cash flow		$	138				$	(17	)			$	298				$	137

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. Adjusted EBITDAX margin is calculated as adjusted EBITDAX divided by Revenues, excluding non-cash derivative gains and losses.
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					4th Quarter
($ millions)		2021					2020					2021					2020
Total revenues		$	304				$	276				$	667				$	849
Non-cash derivative loss		183					9					357					28
Revenues, excluding non-cash derivative gains and losses		$	487				$	285				$	1,024				$	877
Adjusted EBITDAX margin		35		%			7		%			35		%			31		%

OPERATING COSTS PER BOE
The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSC-type contracts.
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
($ per Boe)		2021					2020					2021					2020
Energy operating costs (a)		$	4.70				$	3.51				$	4.70				$	3.61
Gas processing costs		0.66					0.46					0.60					0.57
Non-energy operating costs (b)		13.12					8.45					13.10					10.81
Operating costs		$	18.48				$	12.42				$	18.40				$	14.99
Excess costs attributable to PSC-type contracts		(1.73		)			(0.42		)			(1.66		)			(0.66		)
Operating costs, excluding effects of PSC-type contracts		$	16.75				$	12.00				$	16.74				$	14.33
(a) - Energy operating costs include purchases of fuel gas and electricity used in our operations and internal costs to produce electricity used in our fields.
(b) - Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

Attachment 3
PRODUCTION STATISTICS
		Successor		Predecessor		Successor		Predecessor
Net		2nd Quarter		2nd Quarter		Six Months		Six Months
Oil, NGLs and Natural Gas Production Per Day		2021		2020		2021		2020
Oil (MBbl/d)
San Joaquin Basin		39		41		38		44
Los Angeles Basin		19		27		20		26
Ventura Basin		3		2		2		3
Total		61		70		60		73
NGLs (MBbl/d)
San Joaquin Basin		13		13		12		14
Ventura Basin		—		—		1		—
Total		13		13		13		14
Natural Gas (MMcf/d)
San Joaquin Basin		135		148		135		151
Los Angeles Basin		1		2		1		2
Ventura Basin		5		3		5		4
Sacramento Basin		20		21		20		22
Total		161		174		161		179
Total Production (MBoe/d)		101		112		100		117
		Successor		Predecessor		Successor		Predecessor
Gross Operated and Net Non-Operated		2nd Quarter		2nd Quarter		Six Months		Six Months
Oil, NGLs and Natural Gas Production Per Day		2021		2020		2021		2020
Oil (MBbl/d)
San Joaquin Basin		45		48		45		51
Los Angeles Basin		27		30		27		31
Ventura Basin		3		2		3		3
Total		75		80		75		85
NGLs (MBbl/d)
San Joaquin Basin		14		14		12		14
Ventura Basin		—		—		1		—
Total		14		14		13		14
Natural Gas (MMcf/d)
San Joaquin Basin		144		158		144		160
Los Angeles Basin		8		9		8		9
Ventura Basin		5		3		5		5
Sacramento Basin		24		26		24		28
Total		181		196		181		202
Total Production (MBoe/d)		119		127		118		133

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

Attachment 4
PRICE STATISTICS
		Successor					Predecessor					Successor					Predecessor
		2nd Quarter					2nd Quarter					Six Months					Six Months
		2021					2020					2021					2020
Realized Prices
Oil with hedge ($/Bbl)		$	54.10				$	30.82				$	53.91				$	43.76
Oil without hedge ($/Bbl)		$	68.94				$	30.27				$	64.89				$	41.02
NGLs ($/Bbl)		$	44.90				$	21.05				$	46.75				$	25.18
Natural gas ($/Mcf)		$	3.04				$	1.65				$	3.17				$	1.96
Index Prices
Brent oil ($/Bbl)		$	69.02				$	33.27				$	65.06				$	42.12
WTI oil ($/Bbl)		$	66.07				$	27.85				$	61.96				$	37.01
NYMEX gas ($/MMBtu)		$	2.76				$	1.77				$	2.74				$	1.91
Realized Prices as Percentage of Index Prices
Oil with hedge as a percentage of Brent		78		%			93		%			83		%			104		%
Oil without hedge as a percentage of Brent		100		%			91		%			100		%			97		%
Oil with hedge as a percentage of WTI		82		%			111		%			87		%			118		%
Oil without hedge as a percentage of WTI		104		%			109		%			105		%			111		%
NGLs as a percentage of Brent		65		%			63		%			72		%			60		%
NGLs as a percentage of WTI		68		%			76		%			75		%			68		%
Natural gas as a percentage of NYMEX		110		%			93		%			116		%			103		%

Attachment 5
2ND QUARTER 2021 DRILLING ACTIVITY
		San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled		Basin		Basin		Basin		Basin		Total
Development Wells
Primary		11		—		—		—		11
Waterflood		10		—		—		—		10
Total (1)		21		—		—		—		21
SIX MONTHS 2021 DRILLING ACTIVITY
		San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled		Basin		Basin		Basin		Basin		Total
Development Wells
Primary		28		—		—		—		28
Waterflood		10		—		—		—		10
Total (1)		38		—		—		—		38
(1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.

Attachment 6
CRUDE OIL HEDGES AS OF JUNE 30, 2021
		Q3 2021		Q4 2021		1Q 2022		2Q 2022		2H 2022		FY 2023
Sold Calls:
Barrels per day		36,688		37,037		35,347		35,343		28,773		14,790
Weighted-average Brent price per barrel		$50.47		$60.75		$60.37		$60.63		$59.07		$58.01
Purchased Puts:
Barrels per day		36,943		35,820		35,347		35,343		28,773		14,790
Weighted-average Brent price per barrel		$40.18		$40.19		$40.57		$41.13		$40.70		$40.00
Sold Puts:
Barrels per day		14,647		14,193		6,869		—		2,674		—
Weighted-average Brent price per barrel		$30.00		$32.00		$32.00		—		$32.00		—
Swaps:
Barrels per day		11,063		11,922		10,869		8,669		8,386		6,930
Weighted-average Brent price per barrel		$51.02		$52.61		$52.62		$51.31		$51.22		$52.15

Attachment 7
2021E TOTAL YEAR GUIDANCE
		Total Year 2021E
Total Production (Mboe/d)		97 - 100
Oil Production (Mbbl/d)		60 - 62
Operating Costs ($ millions)		$670 - $695
General and administrative expenses ($ millions)		$180 - $190
Capital ($ millions)		$170 - $190
Adjusted EBITDAX ($ millions)		$725 - $825
Free cash flow ($ millions)		$400 - $500

See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. For FY 2021E guidance, management is not providing guidance on income taxes or any unusual or infrequent events at this time.

		FY 2021 Estimated
($ millions)		Low				High
Net cash provided by operating activities		$	590			$	670
Capital investments		(190		)		(170		)
Estimated free cash flow		$	400			$	500

		FY 2021 Estimated
($ millions)		Low			High
Net income		$	195		$	240
Interest and debt expense, net		50			55
Depreciation, depletion and amortization		190			225
Exploration expense		5			10
Unusual, infrequent and other items		220			220
Other non-cash items
Accretion expense		50			55
Stock-settled compensation		10			15
Post-retirement medical and pension		5			5
Estimated adjusted EBITDAX		$	725		$	825
Net cash provided by operating activities		$	590		$	670
Cash interest		30			35
Exploration expenditures		5			10
Working capital changes		100			110
Estimated adjusted EBITDAX		$	725		$	825

 

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FAQ

What is the updated free cash flow guidance for CRC in 2021?

California Resources Corporation has increased its 2021 free cash flow guidance to $400-$500 million.

How much has CRC raised its Share Repurchase Program to?

CRC has raised its Share Repurchase Program from $150 million to $250 million.

What acquisition did CRC announce in the second quarter of 2021?

CRC announced the acquisition of a 90% working interest in joint venture wells for $53 million.

What are the estimated proceeds from CRC's planned divestiture of its Ventura operations?

The divestiture of CRC's Ventura operations is projected to generate up to $102 million.

What was the net loss reported by CRC for the second quarter of 2021?

CRC reported a net loss attributable to common stock of $111 million, or $1.34 per diluted share.