California Resources Corporation Generates Record $690 Million of Operating Cash Flow and $311 Million of Free Cash Flow in 2022

Rhea-AI Summary

California Resources Corporation (NYSE: CRC) has increased its Share Repurchase Program by nearly 30% to $1.1 billion, fueled by a record operating cash flow of $690 million in 2022. The company returned $372 million to shareholders during the year, including dividends and share repurchases. CRC's carbon management efforts advanced significantly, signing two agreements to sequester 470,000 metric tons of CO2 annually. For 2023, CRC anticipates production of 85,000 to 91,000 barrels of oil equivalent per day. The company reported a net income of $524 million for 2022, equating to $6.75 per share, and expects continued positive cash flow generation moving forward.

Positive

• Increased Share Repurchase Program by $250 million to $1.1 billion.
• Returned $372 million to shareholders in 2022.
• Achieved record operating cash flow of $690 million.
• Signed agreements to sequester 470,000 metric tons of CO2 annually.

Negative

• Reported a net income decline from $612 million in 2021 to $524 million in 2022.
• Average daily net production decreased by approximately 9 MBoe/d year-over-year.

California Resources Corporation Raises its Share Repurchase Program by Nearly 30% to $1.1 Billion and Meaningfully Advances its Carbon Management Business

LONG BEACH, Calif.--(BUSINESS WIRE)-- California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today reported fourth quarter and full year 2022 operational and financial results.

"CRC continued to deliver as we closed out 2022 with record operating cash flow which allowed us to return $372 million to shareholders. Given our positive outlook on 2023 free cash flow generation, we are increasing our Share Repurchase Program to $1.1 billion, a $250 million or nearly 30% increase, with approximately $640 million remaining on our authorization as of December 31, 2022 after taking into account this increase. Our 2023 development plans will utilize current permits in-hand and focus on workovers and maintenance opportunities to maximize cash flow per share," said Mac McFarland, CRC’s President and Chief Executive Officer.

"We continued to build off the momentum we generated throughout the year. In late 2022 and the start of 2023, our Carbon Management Business signed two carbon dioxide management agreements (CDMAs) to sequester 470,000 metric tons (MT) of carbon dioxide (CO₂). Further, we announced the formation of a consortium of organizations across industry, technology, academia, national labs, community, government, and labor to create the California Direct Air Capture (DAC) Hub, reinforcing our dedication and commitment to California’s energy transition. For the balance of 2023, we will continue developing our Carbon Management Business, while making strides in our CalCapture project, filing additional Class VI permits with the EPA and advancing numerous additional CDMAs."

Annual Highlights

• Reported net income attributable to common stock of $524 million, or $6.75 per diluted share. When adjusted for items analysts typically exclude from estimates including noncash mark to market gains and gains on asset divestitures, the Company’s adjusted net income¹ was $384 million, or $4.95 per diluted share
• Generated operating cash flow of $690 million, adjusted EBITDAX¹ of $852 million, free cash flow¹ of $311 million, and E&P, Corporate and Other Free Cash Flow¹ of $362 million in 2022
• Returned $372 million to shareholders in 2022, $59 million in dividends and $313 million through the Share Repurchase Program, while maintaining a strong cash balance of $307 million
• Produced an average of 55,000 barrels of oil per day throughout the year, with total drilling and completions and workover capital expenditures of $278 million in 2022
• Increased the Share Repurchase Program by $250 million to $1.1 billion, extended the program term through June 30, 2024, and repurchased ~14% of the Company's common stock since program inception
• Advanced the Carbon Management Business in California on several fronts:
  • Formed a joint venture with Brookfield Renewables,
  • Submitted Class VI permits to EPA for an additional 94 MMT of CO₂ reservoirs,
  • Executed two CDMAs to sequester 470,000 MT of CO₂ per annum at CTV I and CTV III reservoirs, and
  • Made substantial progress on CalCapture Project with targeted Final Investment Decision (FID) in early 2024
• Through its subsidiary CTV Direct, formed in February 2023 a consortium of organizations across industry, technology, academia, national labs, community, government, and labor that is intended to create California's first DAC Hub

Fourth Quarter 2022 Highlights

Financial

• Reported net income of $83 million, or $1.11 per diluted share. When adjusted for items analysts typically exclude from estimates including mark-to-market adjustments and gains on asset divestitures, the Company’s adjusted net income¹ was $93 million, or $1.24 per diluted share
• Generated net cash provided by operating activities of $114 million, adjusted EBITDAX¹ of $208 million and free cash flow¹ of $39 million
• Ended the quarter with $307 million of cash on hand and an undrawn RBL credit facility representing $765 million of total liquidity²
• Declared a quarterly dividend of $0.2825 per share of common stock, totaling ~$20 million payable on March 16, 2023 to shareholders of record on March 6, 2023, with subsequent quarterly dividends subject to final determination and Board approval
• Repurchased 1,521,190 common shares for $66 million during the fourth quarter of 2022; repurchased an aggregate 11,456,260 shares for $461 million since the inception of the Share Repurchase Program through December 31, 2022

Operations

• Produced an average of 91,000 net barrels of oil equivalent per day (Boe/d), including 55,000 barrels of oil per day (Bo/d), with E&P capital expenditures of $81 million during the quarter
• Operated one drilling rig in the San Joaquin Basin and two drilling rigs in the Los Angeles Basin; drilled 23 wells (23 online in 4Q22)
• Operated 36 maintenance rigs in the fourth quarter

2023 Guidance and Capital Program³

CRC expects its 2023 capital program to range between $200 and $245 million. The program includes $154 to $184 million of adjusted capital for oil and natural gas development⁴, $15 to $25 million of adjusted capital for carbon management projects⁴ and $31 to $36 million for corporate and other activities, including procuring long-lead time items for planned maintenance at CRC's Elk Hills power plant in 2024. The foregoing amounts related to carbon management projects does not include amounts funded by Brookfield through the Carbon TerraVault JV. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on CRC's joint venture with Brookfield. The actual amount of spending under CRC's 2023 capital program will depend on a variety of factors including regulatory and permitting status.

CRC expects to produce between 85,000 and 91,000 Boe/d³ (~60% oil) in 2023. CRC plans to run a development program averaging 1.5 rigs in 2023 for drilling locations for which we already have permits and will otherwise focus on workover and maintenance activity to offset base decline following the ongoing impact of the Kern County EIR litigation.

On a go-forward basis utilizing a 1.5 rig program, CRC would expect to spend ~$155 million in E&P drilling and completions and workover capital. This level of spending excludes one-time items and CMB capital which is expected to be funded by projected CTV JV contributions.

CRC GUIDANCE3		Total 2023E		CMB 2023E		E&P, Corp. & Other 2023E
Net Total Production (MBoe/d)		85 - 91				85 - 91
Net Oil Production (MBbl/d)		51 - 55				51 - 55
Operating Costs ($ millions)		$845 - $895				$845 - $895
CMB Expenses5 ($ millions)		$25 - $35		$25 - $35
Adjusted General and Administrative Expenses1 ($ millions)		$195 - $225		$10 - $15		$185 - $210
Total Capital ($ millions)		$200 - $245		$5 - $15		$195 - $230
Adjusted Total Capital4 ($ millions)		$200 - $245		$15 - $25		$185 - $220
Drilling & Completions		$66 - $76				$66 - $76
Workovers		$44 - $54				$44 - $54
Adjusted Facilities		$44 - $54				$44 - $54
Corporate & Other		$31 - $36				$31 - $36
Adjusted CMB		$15 - $25		$15 - $25
Free Cash Flow1 ($ millions)		$330 - $440		($60) - ($80)		$410 - $500
Natural Gas Trading, Net ($ millions)		$60 - $70				$60 - $70
Net Electricity ($ millions)		$80 - $120				$80 - $120
Transportation Expense ($ millions)		$50 - $70				$50 - $70
ARO Settlement Payments* ($ millions)		$55 - $60				$55 - $60
Taxes Other Than on Income* ($ millions)		$175 - $185				$175 - $185
Interest and Debt Expense* ($ millions)		$55 - $60				$55 - $60
Cash Income Taxes* ($ millions)		$80 - $100				$80 - $100
Commodity Realizations:
Oil - % of Brent:		97% - 99%				97% - 99%
NGL - % of Brent:		58% - 64%				58% - 64%
Natural Gas - % of NYMEX:		150% - 250%				150% - 250%

*Notes: 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively Cash Income Taxes aren’t paid evenly throughout 2023

First Quarter 2023 Guidance and Capital Program³

CRC expects its first quarter 2023 capital program to range between $57 and $69 million assuming normal operating conditions. This includes $2 to $4 million for carbon management projects.

At this level of spending, CRC expects to produce between 89,000 and 91,000 Boe/d³ (~59% oil) in the first quarter of 2023 and plans to run 3 drilling rigs in the Long Beach and San Joaquin basins developing drilling locations for which we already have permits. CRC will also focus on workover activity throughout 2023 to offset base decline following the impact of the Kern County EIR litigation.

CRC sells all of its natural gas not used in its operations into the California market where the majority of these sales are done via bid in monthly method. Given the recent natural gas environment, CRC expects the first quarter of 2023 to benefit on a net basis, particularly in its natural gas revenue and natural gas marketing segments. CRC also expects to see higher costs related to purchased natural gas and energy operating costs, but as CRC is net long natural gas, the benefit will exceed the higher costs.

CRC GUIDANCE3		Total 1Q23E		CMB 1Q23E		E&P, Corp. & Other 1Q23E
Net Total Production (MBoe/d)		89 - 91				89 - 91
Net Oil Production (MBbl/d)		53 - 54				53 - 54
Operating Costs ($ millions)		$260 - $270				$260 - $270
CMB Expenses5 ($ millions)		$5 - $10		$5 - $10
Adjusted General and Administrative Expenses1 ($ millions)		$50 - $58		$3 - $5		$47 - $53
Total Capital ($ millions)		$57 - $69		$2 - $4		$55 - $65
Adjusted Total Capital4 ($ millions)		$57 - $69		$2 - $4		$55 - $65
Free Cash Flow1 ($ millions)		$151 - $180		($15) - ($24)		$175 - $195
Natural Gas Trading, Net ($ millions)		$35 - $45				$35 - $45
Net Electricity ($ millions)		$25 - $35				$25 - $35
Transportation Expense ($ millions)		$14 - $16				$14 - $16
Commodity Realizations:
Oil - % of Brent:		97% - 99%				97% - 99%
NGL - % of Brent:		63% - 65%				63% - 65%
Natural Gas - % of NYMEX*:		400% - 500%				400% - 500%

*Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively.

Fourth Quarter & Full Year 2022 E&P Operational Results

In November 2020, the SEC amended Regulation S-K to, among other things, provide companies with the option to discuss material changes to results of operations between the current and immediately preceding quarter. CRC has elected to discuss its results of operations on a sequential-quarter basis. CRC believes this approach provides more meaningful and useful information to measure its performance from the immediately preceding quarter. In accordance with this final rule, CRC is not required to include a comparison of the current quarter and the same prior-year quarter.

Total daily net production for the three months ended December 31, 2022, compared to the three months ended September 30, 2022 decreased by approximately 1 MBoe/d, or 1%. This decrease is predominately a result of CRC's natural decline and lower development drilling, partially offset by production-sharing contracts (PSCs), which positively impacted CRC's net oil production in the three months ended December, 2022 by approximately 1 MBoe/d, compared to the three months ended September 30, 2022.

Total daily net production for the year ended December 31, 2022, compared to the year ended December 31, 2021 decreased by approximately 9 MBoe/d, or 9%. The decrease was predominately a result of CRC's natural decline and lower development drilling which accounted for approximately 4 MBoe/d and divestitures of certain Ventura basin and Lost Hills assets which accounted for approximately 5 MBoe/d. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions of CRC's 2022 10-K for more information on CRC's divestitures in 2022.

During the fourth quarter of 2022, CRC operated an average of one drilling rig in the San Joaquin Basin and two drilling rigs in the Los Angeles Basin. During the quarter, CRC drilled 23 net wells and brought online 23 wells. See Attachment 3 for further information on CRC's production results by basin and Attachment 5 for further information on CRC's drilling activity.

Fourth Quarter & Full Year 2022 Financial Results

		4th Quarter					3rd Quarter				Total Year					Total Year
($ and shares in millions, except per share amounts)		2022					2022				2022					2021
Statements of Operations:
Revenues
Total operating revenues		$	682				$	1,125			$	2,707				$	1,889
Operating Expenses
Total operating expenses			549					536				1,954					1,720
Gain on asset divestitures			(1	)				2				59					124
Operating Income		$	132				$	591			$	812				$	293
Net Income Attributable to Common Stock		$	83				$	426			$	524				$	612
Net income attributable to common stock per share - basic		$	1.14				$	5.75			$	6.94				$	7.46
Net income attributable to common stock per share - diluted		$	1.11				$	5.58			$	6.75				$	7.37
Adjusted net income1		$	93				$	111			$	384				$	506
Adjusted net income1 per share - diluted		$	1.24				$	1.45			$	4.95				$	6.10
Weighted-average common shares outstanding - basic			72.7					74.1				75.5					82.0
Weighted-average common shares outstanding - diluted			75.0					76.3				77.6					83.0
Adjusted EBITDAX1		$	208				$	234			$	852				$	860

Review of Fourth Quarter & Full Year 2022 Financial Results

Realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, decreased by $10.81 per barrel from $97.96 per barrel in the third quarter of 2022 to $87.15 per barrel in the fourth quarter of 2022. Crude realizations decreased in the fourth quarter of 2022 relative to the third quarter of 2022 as California refining margins tightened significantly leaving those refiners less motivated to secure incremental barrels.

For the year ended December 31, 2022, realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, increased by $27.83 per barrel to $98.26 from $70.43 per barrel in the same period of 2021. Capital and production discipline across domestic and international producers generally offset continued COVID-19 lockdowns in China, reduced energy demand across much of Europe and the release of meaningful quantities of oil from the United States Strategic Petroleum Reserve.

Realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, decreased by $1.12 from $62.45 in the third quarter of 2022 to $61.33 in the fourth quarter of 2022.

For the year ended December 31, 2022, realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, increased by $5.75 to $61.80 from $56.05 per barrel in the same period of 2021. See Attachment 4 for further information on prices.

Adjusted EBITDAX¹ for the fourth quarter of 2022 and for the year ended December 31, 2022, was $208 million and $852 million, respectively. See table below for the Company's net cash provided by operating activities, capital investments and free cash flow¹ during the same periods.

FREE CASH FLOW1
Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with free cash flow of CRC's exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB).
		4th Quarter					3rd Quarter				Total Year					Total Year
($ millions)		2022					2022				2022					2021
Net cash provided by operating activities		$	114				$	235			$	690				$	660
Capital investments			(75	)				(107	)			(379	)				(194	)
Free cash flow1			39					128				311					466
E&P, corporate & other free cash flow1		$	61				$	139			$	362				$	472
CMB free cash flow1		$	(22	)			$	(11	)		$	(51	)			$	—

The following table presents key operating data for CRC's oil and gas operations, on a per BOE basis, for the periods presented below. Energy operating costs consist of purchased natural gas used to generate electricity for CRC's operations and steam for its steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchased natural gas used to generate steam in CRC's steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation.

OPERATING COSTS PER BOE
The reporting of PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC's net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs.
		4th Quarter					3rd Quarter				Total Year					Total Year
($ per Boe)		2022					2022				2022					2021
Energy operating costs		$	9.56				$	10.96			$	9.76				$	7.01
Gas processing costs			0.48					0.49				0.52					0.54
Non-energy operating costs			13.82					13.82				13.47					11.84
Operating costs		$	23.86				$	25.27			$	23.75				$	19.39
Excess costs attributable to PSCs		$	(1.90	)				(2.16	)		$	(2.23	)				(1.83	)
Operating costs, excluding effects of PSCs (a)		$	21.96				$	23.11			$	21.52				$	17.56

(a)		Operating costs, excluding effects of PSCs is a non-GAAP measure.

Energy operating costs for the fourth quarter of 2022 were $80 million, or $9.56 per Boe, which was a decrease of $13 million or 14% from $93 million, or $10.96 per Boe, for the third quarter of 2022. This decrease was primarily a result of lower production and lower electricity and natural gas prices.

Energy operating costs for the year ended December 31, 2022 were $323 million, or $9.76 per Boe, which was an increase of $68 million or 27% from $255 million, or $7.01 per Boe, in the same period of 2021. The increase was predominantly a result of higher prices for purchased natural gas, which CRC uses to generate electricity for its operations and steam for its steamfloods, and for purchased electricity.

Non-energy operating costs for the fourth quarter of 2022 were $116 million, or $13.82 per Boe, which was a decrease of $1 million or 1% from $117 million, or $13.82 per Boe, for the third quarter of 2022. This decrease was primarily a result of lower surface maintenance.

Non-energy operating costs for the year ended December 31, 2022 were $445 million, or 13.47 per Boe, which was an increase of $15 million or 3% from $430 million, or 11.84 per Boe, in the same period of 2021. This increase was primarily a result of increased surface and downhole maintenance activity in 2022.

Sustainability & Carbon Management Update

In December 2022, Carbon TerraVault JV entered into a CDMA with Lone Cypress, an independent energy company focused on the development of low-carbon hydrogen generation facilities and energy infrastructure, to sequester 100,000 MT of CO₂ per annum from a newly constructed blue hydrogen plant at the Elk Hills Field in Kern County.

Also in December 2022, CRC received an A- from CDP for its 2022 climate disclosure, securing a score at CDP’s Leadership Level for the fourth year in a row. This accomplishment is further evidence of CRC’s commitment to maintaining a strong ESG and sustainability platform.

In January 2023, CTV entered into a CDMA with Grannus, an independent clean-tech company that is building a portfolio of blue ammonia and hydrogen production facilities to supply the agriculture, mobility and marine fuel markets, to sequester 370,000 MT of CO₂ per annum at CTV III from a new blue ammonia and hydrogen plant to be constructed in Northern California. Called the Grannus Blue Ammonia and Hydrogen Project, the project aims to be California’s first blue ammonia and hydrogen facility producing 150,000 MT per annum of blue ammonia and 10,000 MT per annum of blue hydrogen.

In February 2023, CRC assembled a consortium of organizations across industry, technology, academia, national labs, community, government, and labor, to pursue U.S. Department of Energy (DOE) funding under its Regional DAC Hubs Initiative to create the California DAC Hub, the state’s first full-scale DAC plus storage (DAC+S) network of regional DAC+S hubs. DAC+S is a solution that can remove and then permanently store atmospheric CO₂ using low carbon emission energy and provide economic benefits to surrounding communities.

The California DAC Hub is expected to accelerate California’s progress to achieve its carbon neutrality goal while prioritizing the surrounding under-represented California communities in several areas including: air quality improvements, increased renewable energy use and enhanced water management including water reclamation and production of new water sources. Further, CRC expects that the hub will provide high quality union jobs while enhancing local area education programs in science, technology and math (STEM) along with energy transition.

Balance Sheet and Liquidity Update

CRC's aggregate commitment under the Revolving Credit Facility was $602 million as of December 31, 2022. The borrowing base for the Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.2 billion on October 25, 2022.

As of December 31, 2022, CRC had liquidity of $765 million, which consisted of $307 million in unrestricted cash and $458 million of available borrowing capacity under its Revolving Credit Facility which is net of $144 million of letters of credit.

Acquisitions and Divestitures

On February 1, 2022, CRC sold its 50% non-operated working interest in certain horizons within its Lost Hills field, located in the San Joaquin basin, recognizing a gain of $49 million. CRC retained an option to capture, transport and store 100% of the CO₂ from steam generators across the Lost Hills field for future carbon management projects. CRC also retained 100% of the deep rights and related seismic data.

In June 2022, CRC sold its commercial office building located in Bakersfield, California for net proceeds of $13 million, recognizing no gain or loss on sale.

During the year ended December 31, 2022, CRC recognized a gain of $11 million related to the sale of certain Ventura basin assets. The closing of the sale of CRC's remaining assets in the Ventura basin is subject to final approval from the State Lands Commission, which it expects to receive prior to the end of the first quarter of 2023. These remaining assets, consisting of property, plant and equipment and associated asset retirement obligations, are classified as held for sale on CRC's consolidated balance sheet as of December 31, 2022.

Also in 2022, CRC sold non-core assets recognizing a $1 million loss and acquired properties for carbon management activities for ~$17 million.

Shareholder Return Strategy

CRC continues to prioritize shareholder returns and therefore dedicates a significant portion of its free cash flow to shareholders in the form of dividends and share repurchases. To that end, CRC’s Board of Directors approved an increase of the Share Repurchase Program to $1.1 billion, an increase of $250 million and extended the program through June 30, 2024. Adjusting for this increase, CRC has $640 million of capacity remaining under the repurchase program as of December 31, 2022.

During the fourth quarter of 2022, CRC repurchased 1.5 million shares for $66 million or an average price of $43.17/share. Since the inception of the Share Repurchase Program in May 2021, 11,456,260 shares have been repurchased for $461 million at an average price of $40.19 per share. These total repurchases represent 14% of CRC’s shares outstanding at its bankruptcy emergence in October 2020.

On February 23, 2023, CRC's Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record on March 6, 2023 and will be paid on March 16, 2023.

Through December 31, 2022, CRC has returned $534 million of cash to its shareholders, including $461 million in share repurchases and $73 million of dividends. These figures exclude share repurchases made to-date in 2023 as well as the $20 million fourth quarter dividend declared and payable in March 2023.

Reserves

As of December 31, 2022, CRC’s proved reserves totaled an estimated 417 million BOE, of which 363 million BOE was proved developed and 54 million BOE was proved undeveloped. The estimated future net cash flows of our proved reserve volumes had a PV-10¹ value of $9.2 billion. These estimates were based on SEC pricing and the average realized prices for estimating CRC's PV-10¹ of cash flows as of December 31, 2022, were $97.50 per barrel for oil, $67.83 per barrel for NGLs and $7.84 per Mcf for natural gas.

PV-10 AND STANDARDIZED MEASURE
The following table presents a reconciliation of the GAAP financial measure of Standardized Measure of discounted future net cash flows (Standardized Measure) to the non-GAAP financial measure of PV-10:
($ millions)		December 31, 2022
Standardized Measure of discounted future net cash flows		$	6,726
Present value of future income taxes discounted at 10%			2,493
PV-10 of cash flows (*)		$	9,219
(*) PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.

Upcoming Investor Conference Participation

CRC's executives will be participating in the following events in February and March of 2023:

• Credit Suisse Vail Summit on February 26 in Vail, CO
• MS Global Energy and Power Conference on March 1 in New York, NY
• CERAWeek 2023 on March 6 to 8 in Houston, TX
• 7th Annual Mizuho Energy Summit on March 12 in Napa, CA

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

Conference Call Details

To participate in the conference call scheduled for February 24, 2023, at 1:00 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/10173792/f5508a95c0. 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 PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, free cash flow and free cash flow, after special items, including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2023 and 1Q23 estimates of the non-GAAP measure of free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
(2)		Calculated as $307 million of available cash plus $602 million of capacity on CRC's Revolving Credit Facility less $144 million in outstanding letters of credit.
(3)		Current guidance assumes a 2023 Brent price of $79.12 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $4.27 per mcf and a 1Q23 Brent price of $79.81 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $4.46 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
(4)		Adjusted E&P Capital and Adjusted CMB Capital are Non-GAAP measures. These measures reflect the reclassification of ~$11 million from E&P, Corporate & Other Capital to Adjusted CMB Capital related to the expected 2023 investment in facilities to advance carbon sequestration activities beginning in 2Q23. For the full year 2023 and 1Q23 estimates of the non-GAAP measure of free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
(5)		CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.

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 US and CRC is focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com. Nothing herein is intended to imply or create a legal partnership between Brookfield Global Transition Fund, California Resources Corporation, or any of their respective subsidiaries and affiliates.

Forward-Looking Statements

This document contains statements that CRC believes to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond CRC's control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC's actual results to be materially different than those expressed in its forward-looking statements include:

• fluctuations in commodity prices, including supply and demand considerations for CRC's products and services;
• decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
• government policy, war and political conditions and events, including the war in Ukraine and oil sanctions on Russia, Iran and others;
• regulatory actions and changes that affect the oil and gas industry generally and CRC in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or CRC's carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of CRC's products;
• the impact of inflation on future expenses and changes generally in the prices of goods and services;
• changes in business strategy and CRC's capital plan;
• lower-than-expected production or higher-than-expected production decline rates;
• changes to CRC's estimates of reserves and related future cash flows, including changes arising from CRC's inability to develop such reserves in a timely manner, and any inability to replace such reserves;
• the recoverability of resources and unexpected geologic conditions;
• general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
• production-sharing contracts' effects on production and operating costs;
• the lack of available equipment, service or labor price inflation;
• limitations on transportation or storage capacity and the need to shut-in wells;
• any failure of risk management;
• results from operations and competition in the industries in which CRC operates;
• CRC's ability to realize the anticipated benefits from prior or future efforts to reduce costs;
• environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
• the creditworthiness and performance of CRC's counterparties, including financial institutions, operating partners, CCS project participants and other parties;
• reorganization or restructuring of CRC's operations;
• CRC's ability to claim and utilize tax credits or other incentives in connection with its CCS projects,
• CRC's ability to realize the benefits contemplated by its energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
• CRC's ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV;
• CRC's ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
• uncertainty around the accounting of emissions and CRC's ability to successfully gather and verify emissions data and other environmental impacts.
• changes to CRC's dividend policy and Share Repurchase Program, and its ability to declare future dividends or repurchase shares under its debt agreements;
• limitations on CRC's financial flexibility due to existing and future debt;
• insufficient cash flow to fund CRC's capital plan and other planned investments and return capital to shareholders;
• changes in interest rates, and CRC's access to and the terms of credit in commercial banking and capital markets, including its ability to refinance its debt or obtain separate financing for its carbon management business;
• changes in state, federal or international tax rates, including CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
• effects of hedging transactions;
• the effect of CRC's stock price on costs associated with incentive compensation;
• inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and CRC's ability to achieve any expected synergies;
• disruptions due to earthquakes, forest fires, floods or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19; and
• other factors discussed in Part I, Item 1A – Risk Factors in CRC's Annual Report on Form 10-K and its other SEC filings available at www.crc.com.

CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and CRC undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and do not warrant the accuracy or completeness of such third-party information.

Attachment 1
SUMMARY OF RESULTS
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ and shares in millions, except per share amounts)		2022				2022				2021				2022				2021
Statements of Operations:
Revenues
Oil, natural gas and NGL sales		$	617			$	680			$	589			$	2,643			$	2,048
Net (loss) gain from commodity derivatives			(132	)			243				(73	)			(551	)			(676	)
Sales of purchased natural gas			94				113				71				314				312
Electricity sales			90				88				41				261				172
Other revenue			13				1				6				40				33
Total operating revenues			682				1,125				634				2,707				1,889
Operating Expenses
Operating costs			199				214				182				785				705
General and administrative expenses			59				59				53				222				200
Depreciation, depletion and amortization			49				50				53				198				213
Asset impairments			—				—				—				2				28
Taxes other than on income			42				44				32				162				145
Exploration expense			1				1				1				4				7
Purchased natural gas expense			87				98				52				273				196
Electricity generation expenses			68				42				26				167				96
Transportation costs			13				13				14				50				51
Accretion expense			11				10				11				43				50
Other operating expenses, net			20				5				(2	)			48				29
Total operating expenses			549				536				422				1,954				1,720
Net (loss) gain on asset divestitures			(1	)			2				120				59				124
Operating Income			132				591				332				812				293
Non-Operating (Expenses) Income
Reorganization items, net			—				—				(1	)			—				(6	)
Interest and debt expense			(14	)			(13	)			(14	)			(53	)			(54	)
Loss from investment in unconsolidated subsidiaries			(1	)			—				—				(1	)			—
Net loss on early extinguishment of debt			—				—				—				—				(2	)
Other non-operating income (expenses), net			—				1				1				3				(2	)
Net Income Before Income Taxes			117				579				318				761				229
Income tax (provision) benefit			(34	)			(153	)			396				(237	)			396
Net income			83				426				714				524				625
Net income attributable to noncontrolling interests			—				—				—				—				(13	)
Net Income Attributable to Common Stock		$	83			$	426			$	714			$	524			$	612
Net income attributable to common stock per share - basic		$	1.14			$	5.75			$	8.91			$	6.94			$	7.46
Net income attributable to common stock per share - diluted		$	1.11			$	5.58			$	8.71			$	6.75			$	7.37
Adjusted net income		$	93			$	111			$	175			$	384			$	506
Adjusted net income per share - basic		$	1.28			$	1.50			$	2.18			$	5.09			$	6.17
Adjusted net income per share - diluted		$	1.24			$	1.45			$	2.13			$	4.95			$	6.10
Weighted-average common shares outstanding - basic			72.7				74.1				80.1				75.5				82.0
Weighted-average common shares outstanding - diluted			75.0				76.3				82.0				77.6				83.0
Adjusted EBITDAX		$	208			$	234			$	260			$	852			$	860
Effective tax rate			29	%			26	%			(125	)%			31	%			(173	)%
GAINS AND LOSSES FROM COMMODITY DERIVATIVES
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)		2022				2022				2021				2022				2021
Non-cash derivative gain (loss)		$	2			$	425			$	26			$	187			$	(357	)
Net payments on settled commodity contracts			(134	)			(182	)			(99	)			(738	)			(319	)
Net (loss) gain from commodity derivatives		$	(132	)		$	243			$	(73	)		$	(551	)		$	(676	)

CAPITAL INVESTMENTS
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)		2022				2022				2021				2022				2021
Facilities (1)		$	19			$	20			$	14			$	71			$	43
Drilling			48				73				46				242				119
Workovers			14				7				2				36				27
Total E&P capital			81				100				62				349				189
CMB (1)(2)			(13	)			6				—				4				—
Corporate and other			7				1				4				26				5
Total capital program		$	75			$	107			$	66			$	379			$	194

(1)		Total year 2022 facilities capital includes $12 million to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported this $12 million of capital as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed $12 million from facilities capital for total E&P, Corporate and Other.
(2)		In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.

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 its financial condition, results of operations and cash flows. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, E&P, Corporate & Other adjusted EBITDAX, CMB adjusted EBITDAX, free cash flow, E&P, Corporate & Other free cash flow, CMB free cash flow, adjusted general and administrative expenses, operating costs per BOE, and adjusted total capital 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. CRC defines 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 and net income attributable to common stock per share to the non-GAAP financial measure of adjusted net income and adjusted net income per share.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions, except per share amounts)		2022				2022				2021				2022				2021
Net income		$	83			$	426			$	714			$	524			$	625
Net income attributable to noncontrolling interests			—				—				—				—				(13	)
Net income attributable to common stock			83				426				714				524				612
Unusual, infrequent and other items:
Non-cash derivative (gain) loss			(2	)			(425	)			(26	)			(187	)			357
Asset impairments			—				—				—				2				28
Reorganization items, net			—				—				1				—				6
Severance and termination costs			—				—				—				—				15
Net loss on early extinguishment of debt			—				—				—				—				2
Net loss (gain) on asset divestitures			1				(2	)			(120	)			(59	)			(124	)
Rig termination expenses			2				—				—				2				2
Other, net			13				4				2				20				4
Total unusual, infrequent and other items			14				(423	)			(143	)			(222	)			290
Income tax (benefit) provision of adjustments at effective tax rate			(4	)			120				—				63				—
Income tax (benefit) provision - out of period			—				(12	)			(396	)			19				(396	)
Adjusted net income attributable to common stock		$	93			$	111			$	175			$	384			$	506
Net income attributable to common stock per share - basic		$	1.14			$	5.75			$	8.91			$	6.94			$	7.46
Net income attributable to common stock per share - diluted		$	1.11			$	5.58			$	8.71			$	6.75			$	7.37
Adjusted net income per share - basic		$	1.28			$	1.50			$	1.85			$	5.09			$	6.17
Adjusted net income per share - diluted		$	1.24			$	1.45			$	1.83			$	4.95			$	6.10

ADJUSTED EBITDAX
CRC defines 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. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its 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 CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of its financial covenants under CRC's 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 represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which management believes is a useful measure for investors to understand the results of the core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB).
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions, except per BOE amounts)		2022				2022				2021				2022				2021
Net income		$	83			$	426			$	714			$	524			$	625
Interest and debt expense			14				13				14				53				54
Depreciation, depletion and amortization			49				50				53				198				213
Income tax provision (benefit)			34				153				(396	)			237				(396	)
Exploration expense			1				1				1				4				7
Interest income			(3	)			(1	)			—				(4	)			—
Unusual, infrequent and other items (1)			14				(423	)			(143	)			(222	)			290
Non-cash items
Accretion expense			11				10				11				43				50
Stock-based compensation			4				5				4				17				14
Post-retirement medical and pension			1				—				2				2				3
Adjusted EBITDAX		$	208			$	234			$	260			$	852			$	860
Net cash provided by operating activities		$	114			$	235			$	204			$	690			$	660
Cash interest payments			2				23				2				50				31
Cash interest received			(3	)			(1	)			—				(4	)			—
Cash income taxes			—				—				—				20				—
Exploration expenditures			1				1				1				4				7
Working capital changes			94				(24	)			53				92				162
Adjusted EBITDAX		$	208			$	234			$	260			$	852			$	860
E&P, Corporate & Other Adjusted EBITDAX		$	223			$	239			$	242			$	879			$	600
CMB Adjusted EBITDAX		$	(15	)		$	(5	)		$	—			$	(27	)		$	—
Adjusted EBITDAX per Boe		$	24.94			$	27.63			$	29.22			$	25.77			$	23.65

(1)

See Adjusted Net Income (Loss) reconciliation.

FREE CASH FLOW
Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with free cash flow of its exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results of CRC's core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB).   CRC has also excluded bankruptcy related fees during 2021 as a supplemental measure of its free cash flow.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)		2022				2022				2021				2022				2021
Net cash provided by operating activities		$	114			$	235			$	204			$	690			$	660
Capital investments			(75	)			(107	)			(66	)			(379	)			(194	)
Free cash flow			39				128				138				311				466
Bankruptcy related fees			—				—				1				—				6
Free cash flow, after special items		$	39			$	128			$	139			$	311			$	472
E&P, Corporate and Other Free Cash Flow		$	61			$	139			$	139			$	362			$	472
CMB Free Cash Flow		$	(22	)		$	(11	)		$	—			$	(51	)		$	—

ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing our costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (Adjusted General & Administrative Expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results for CRC's core oil and gas business. CRC defines Adjusted General & Administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB).
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ millions)		2022				2022				2021				2022				2021
General and administrative expenses		$	59			$	59			$	53			$	222			$	200
Stock-based compensation			(4	)			(5	)			(4	)			(17	)			(14	)
Other			(2	)			(1	)			—				(4	)			—
Adjusted G&A expenses		$	53			$	53			$	49			$	201			$	186
E&P, Corporate and Other Adjusted G&A expenses		$	51			$	48			$	49			$	189			$	186
CMB Adjusted G&A expenses		$	2			$	5			$	—			$	12			$	—
OPERATING COSTS PER BOE
The reporting of PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC's net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs.
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
($ per BOE)		2022				2022				2021				2022				2021
Energy operating costs (1)		$	9.56			$	10.96			$	8.04			$	9.76			$	7.01
Gas processing costs (2)			0.48				0.49				0.41				0.52				0.54
Non-energy operating costs (3)			13.82				13.82				12.00				13.47				11.84
Operating costs		$	23.86			$	25.27			$	20.45			$	23.75			$	19.39
Costs attributable to PSCs
Excess energy operating costs attributable to PSCs		$	(0.76	)		$	(0.97	)		$	(0.82	)		$	(0.92	)		$	(0.68	)
Excess non-energy operating costs attributable to PSCs			(1.14	)			(1.19	)			(1.31	)			(1.31	)			(1.15	)
Excess costs attributable to PSCs		$	(1.90	)		$	(2.16	)		$	(2.13	)		$	(2.23	)		$	(1.83	)
Energy operating costs, excluding effect of PSCs (1)		$	8.80			$	9.99			$	7.22			$	8.84			$	6.33
Gas processing costs, excluding effect of PSCs (2)			0.48				0.49				0.41				0.52				0.54
Non-energy operating costs, excluding effect of PSCs (3)			12.68				12.63				10.69				12.16				10.69
Operating costs, excluding effects of PSCs		$	21.96			$	23.11			$	18.32			$	21.52			$	17.56

(1)		Energy operating costs consist of purchased natural gas used to generate electricity for operations and steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations.
(2)		Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills.
(3)		Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchased natural gas used to generate steam in CRC's steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation.

Attachment 3
PRODUCTION STATISTICS
		4th Quarter			3rd Quarter			4th Quarter			Total Year			Total Year
Net Production Per Day		2022			2022			2021			2022			2021
Oil (MBbl/d)
San Joaquin Basin		36			36			40			37			39
Los Angeles Basin		19			19			18			18			19
Ventura Basin		—			—			1			—			2
Total		55			55			59			55			60
NGLs (MBbl/d)
San Joaquin Basin		11			12			12			11			13
Total		11			12			12			11			13
Natural Gas (MMcf/d)
San Joaquin Basin		129			131			131			129			135
Los Angeles Basin		1			1			1			1			1
Ventura Basin		—			—			2			—			4
Sacramento Basin		17			17			19			17			19
Total		147			149			153			147			159
Total Production (MBoe/d)		91			92			97			91			100
Gross Operated and Net Non-Operated		4th Quarter			3rd Quarter			4th Quarter			Total Year			Total Year
Production Per Day		2022			2022			2021			2022			2021
Oil (MBbl/d)
San Joaquin Basin		40			40			45			41			45
Los Angeles Basin		25			26			26			25			27
Ventura Basin		—			—			1			—			2
Total		65			66			72			66			74
NGLs (MBbl/d)
San Joaquin Basin		12			13			13			12			13
Total		12			13			13			12			13
Natural Gas (MMcf/d)
San Joaquin Basin		136			140			138			136			142
Los Angeles Basin		8			7			7			7			8
Ventura Basin		—			—			2			—			4
Sacramento Basin		21			21			24			22			24
Total		165			168			171			165			178
Total Production (MBoe/d)		105			107			114			106			117
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
		4th Quarter				3rd Quarter				4th Quarter				Total Year				Total Year
		2022				2022				2021				2022				2021
Oil ($ per Bbl)
Realized price with derivative settlements		$	61.33			$	62.45			$	61.00			$	61.80			$	56.05
Realized price without derivative settlements		$	87.15			$	97.96			$	78.99			$	98.26			$	70.43
NGLs ($/Bbl)		$	56.55			$	57.68			$	67.61			$	64.33			$	53.62
Natural gas ($/Mcf)
Realized price with derivative settlements		$	8.51			$	8.58			$	5.94			$	7.54			$	4.20
Realized price without derivative settlements		$	8.73			$	8.80			$	5.94			$	7.68			$	4.22
Index Prices
Brent oil ($/Bbl)		$	88.60			$	97.81			$	79.80			$	98.89			$	70.79
WTI oil ($/Bbl)		$	82.64			$	91.56			$	77.19			$	94.23			$	67.91
NYMEX contract month average ($/MMBtu)		$	6.76			$	7.85			$	5.27			$	6.36			$	3.61
NYMEX average monthly settled price ($/MMBtu)		$	6.26			$	8.20			$	5.83			$	6.64			$	3.84
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent			69	%			64	%			76	%			62	%			79	%
Oil without derivative settlements as a percentage of Brent			98	%			100	%			99	%			99	%			99	%
Oil with derivative settlements as a percentage of WTI			74	%			68	%			79	%			66	%			83	%
Oil without derivative settlements as a percentage of WTI			105	%			107	%			102	%			104	%			104	%
NGLs as a percentage of Brent			64	%			59	%			85	%			65	%			76	%
NGLs as a percentage of WTI			68	%			63	%			88	%			68	%			79	%
Natural gas with derivative settlements as a percentage of NYMEX contract month average			126	%			109	%			113	%			119	%			116	%
Natural gas with derivative settlements as a percentage of NYMEX average monthly settled price			136	%			105	%			102	%			114	%			109	%
Natural gas without derivative settlements as a percentage of NYMEX contract month average			129	%			112	%			113	%			121	%			117	%
Natural gas without derivative settlements as a percentage of NYMEX average monthly settled price			139	%			107	%			102	%			116	%			110	%

Attachment 5
FOURTH QUARTER 2022 DRILLING ACTIVITY
		San Joaquin			Los Angeles			Ventura			Sacramento
Wells Drilled		Basin			Basin			Basin			Basin			Total
Development Wells
Primary		1			—			—			—			1
Waterflood		—			16			—			—			16
Steamflood		6			—			—			—			6
Total (1)		7			16			—			—			23
TOTAL YEAR 2022 DRILLING ACTIVITY
		San Joaquin			Los Angeles			Ventura			Sacramento
Wells Drilled		Basin			Basin			Basin			Basin			Total
Development Wells
Primary		18			—			—			—			18
Waterflood		27			41			—			—			68
Steamflood		61			—			—			—			61
Total (1)		106			41			—			—			147

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

Attachment 6
OIL HEDGES AS OF DECEMBER 31, 2022
		Q1 2023		Q2 2023		Q3 2023		Q4 2023		2024
Sold Calls
Barrels per day		18,322		17,837		17,363		5,747		—
Weighted-average Brent price per barrel		$57.28		$60.00		$57.06		$57.06		—
Swaps
Barrels per day		16,620		16,475		16,697		26,094		1,492
Weighted-average Brent price per barrel		$69.46		$68.53		$68.33		$70.18		$79.06
Net Purchased Puts (1)
Barrels per day		18,322		17,837		17,363		5,747		1,724
Weighted-average Brent price per barrel		$76.25		$76.25		$76.25		$76.25		$75.00

(1)		Purchased puts and sold puts with the same strike price have been presented on a net basis.

Attachment 7
		2023 Estimated
TOTAL CRC GUIDANCE1		Consolidated		CMB		E&P, Corporate & Other
Net Total Production (MBoe/d)		85 - 91				85 - 91
Net Oil Production (MBbl/d)		51 - 55				51 - 55
Operating Costs ($ millions)		$845 - $895				$845 - $895
CMB Expenses2 ($ millions)		$25 - $35		$25 - $35
Adjusted General and Administrative Expenses ($ millions)		$195 - $225		$10 - $15		$185 - $210
Total Capital ($ millions)		$200 - $245		$5 - $15		$195 - $230
Adjusted Total Capital3 ($ millions)		$200 - $245		$15 - $25		$185 - $220
Free Cash Flow ($ millions)		$330 - $440		($60) - ($80)		$410 - $500
Natural Gas Trading, Net ($ millions)		$60 - $70				$60 - $70
Net Electricity ($ millions)		$80 - $120				$80 - $120
Transportation Expense ($ millions)		$50 - $70				$50 - $70
ARO Settlement Payments* ($ millions)		$55 - $60				$55 - $60
Taxes Other Than on Income* ($ millions)		$175 - $185				$175 - $185
Interest and Debt Expense* ($ millions)		$55 - $60				$55 - $60
Cash Income Taxes* ($ millions)		$80 - $100				$80 - $100
Commodity Realizations:
Oil - % of Brent:		97% - 99%				97% - 99%
NGL - % of Brent:		58% - 64%				58% - 64%
Natural Gas - % of NYMEX*:		150% - 250%				150% - 250%

*Notes: 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively Cash Income Taxes aren’t paid evenly throughout 2023 Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively.

		1Q23 Estimated
Total CRC GUIDANCE1		Consolidated		CMB		E&P, Corporate & Other
Net Total Production (MBoe/d)		89 - 91				89 - 91
Net Oil Production (MBbl/d)		53 - 54				53 - 54
Operating Costs ($ millions)		$260 - $270				$260 - $270
CMB Expenses2 ($ millions)		$5 - $10		$5 - $10
Adjusted General and Administrative Expenses ($ millions)		$50 - $58		$3 - $5		$47 - $53
Total Capital ($ millions)		$57 - $69		$2 - $4		$55 - $65
Adjusted Total Capital3 ($ millions)		$57 - $69		$2 - $4		$55 - $65
Free Cash Flow ($ millions)		$151 - $180		($15) - ($24)		$175 - $195
Natural Gas Trading, Net ($ millions)		$35 - $45				$35 - $45
Net Electricity ($ millions)		$25 - $35				$25 - $35
Transportation Expense ($ millions)		$14 - $16				$14 - $16
Commodity Realizations:
Oil - % of Brent:		97% - 99%				97% - 99%
NGL - % of Brent:		63% - 65%				63% - 65%
Natural Gas - % of NYMEX:		400% - 500%				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. CRC has supplemented its non-GAAP measures of consolidated free cash flow with free cash flow from our exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less free cash flow attributable to CMB.

ESTIMATED FREE CASH FLOW RECONCILIATION
		2023 Estimated
		Consolidated								CMB								E&P, Corporate & Other
($ millions)		Low				High				Low				High				Low				High
Net cash provided (used) by operating activities		$	575			$	640			$	(55	)		$	(45	)		$	630			$	685
Adjusted capital investments3			(245	)			(200	)			(25	)			(15	)			(220	)			(185	)
Estimated free cash flow		$	330			$	440			$	(80	)		$	(60	)		$	410			$	500
		1Q23 Estimated
		Consolidated								CMB								E&P, Corporate & Other
($ millions)		Low				High				Low				High				Low				High
Net cash provided (used) by operating activities		$	220			$	237			$	(20	)		$	(13	)		$	240			$	250
Capital investments			(69	)			(57	)			(4	)			(2	)			(65	)			(55	)
Estimated free cash flow		$	151			$	180			$	(24	)		$	(15	)		$	175			$	195

ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
		2023 Estimated
		Consolidated								CMB						E&P, Corporate & Other
($ millions)		Low				High				Low			High			Low				High
General and administrative expenses		$	235			$	250			$	10		$	15		$	225			$	235
Equity-settled stock-based compensation			(25	)			(15	)									(25	)			(15	)
Other			(15	)			(10	)									(15	)			(10	)
Estimated adjusted general and administrative expenses		$	195			$	225			$	10		$	15		$	185			$	210
		1Q23 Estimated
		Consolidated								CMB						E&P, Corporate & Other
($ millions)		Low				High				Low			High			Low				High
General and administrative expenses		$	62			$	66			$	3		$	5		$	59			$	61
Equity-settled stock-based compensation			(7	)			(5	)									(7	)			(5	)
Other			(5	)			(3	)									(5	)			(3	)
Estimated adjusted general and administrative expenses		$	50			$	58			$	3		$	5		$	47			$	53

(1)		2023E guidance assumes a 2023 Brent price of $79.12 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $4.27 per mcf. 1Q23E guidance assumes a 1Q23 Brent price of $79.81 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $4.46 per mcf. CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline.
(2)		CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
(3)		Adjusted E&P Capital and Adjusted CMB Capital are Non-GAAP measures. These measures reflect ~$11 million from E&P, Corporate & Other Capital to Adjusted CMB Capital related to the expected 2023 investment in facilities to advance carbon sequestration activities beginning in 2Q23.

 

View source version on businesswire.com: https://www.businesswire.com/news/home/20230224005093/en/

Joanna Park (Investor Relations)

818-661-3731

Joanna.Park@crc.com



Richard Venn (Media)

818-661-6014

Richard.Venn@crc.com

Source: California Resources Corporation

FAQ

What is CRC's new share repurchase program amount?

CRC has raised its share repurchase program to $1.1 billion, a nearly 30% increase.

What were California Resources Corporation's financial highlights for 2022?

CRC reported a net income of $524 million and operating cash flow of $690 million for 2022.

How much CO2 does CRC plan to sequester with its carbon management agreements?

CRC has signed agreements to sequester a total of 470,000 metric tons of CO2 per annum.

What is CRC's production forecast for 2023?

CRC expects to produce between 85,000 and 91,000 barrels of oil equivalent per day in 2023.

How much cash did CRC return to shareholders in 2022?

CRC returned $372 million to shareholders in 2022 through dividends and share repurchases.