# EDGAR Filing Document

**Accession Number:** 0001609253
**File Stem:** 0001609253-23-000015
**Filing Date:** 2023-2
**Character Count:** 157593
**Document Hash:** d988b9542a48d7c830ccfcfec8989b76
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001609253-23-000015.hdr.sgml**: 20230224

**ACCESSION NUMBER**: 0001609253-23-000015

**CONFORMED SUBMISSION TYPE**: 8-K

**PUBLIC DOCUMENT COUNT**: 16

**CONFORMED PERIOD OF REPORT**: 20230224

**ITEM INFORMATION**: Results of Operations and Financial Condition

**ITEM INFORMATION**: Regulation FD Disclosure

**ITEM INFORMATION**: Financial Statements and Exhibits

**FILED AS OF DATE**: 20230224

**DATE AS OF CHANGE**: 20230224

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** California Resources Corp
- **CENTRAL INDEX KEY:** 0001609253
- **STANDARD INDUSTRIAL CLASSIFICATION:** CRUDE PETROLEUM & NATURAL GAS [1311]
- **IRS NUMBER:** 465670947
- **STATE OF INCORPORATION:** DE
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 8-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-36478
- **FILM NUMBER:** 23662342

**BUSINESS ADDRESS:**
- **STREET 1:** 1 WORLD TRADE CENTER
- **STREET 2:** SUITE 1500
- **CITY:** LONG BEACH
- **STATE:** CA
- **ZIP:** 90831
- **BUSINESS PHONE:** 8888484754

**MAIL ADDRESS:**
- **STREET 1:** 1 WORLD TRADE CENTER
- **STREET 2:** SUITE 1500
- **CITY:** LONG BEACH
- **STATE:** CA
- **ZIP:** 90831

?xml version="1.0" ? crc-20230224

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

_____________________

**FORM 8-K** 

_____________________

**CURRENT REPORT**

**PURSUANT TO SECTION 13 OR 15(d) OF THE** 

**SECURITIES EXCHANGE ACT OF 1934**

**Date of report (Date of earliest event reported): February 24, 2023** 

_____________________

**California Resources Corporation**

(Exact Name of Registrant as Specified in its Charter)

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| | | | |
|:---|:---|:---|:---|
| **Delaware** | **001-36478** | **001-36478** | **46-5670947** |
| (State or Other Jurisdiction of <br>Incorporation) | (Commission<br>File Number) | (Commission<br>File Number) | (IRS Employer <br>Identification No.) |
| **1 World Trade Center** | **1 World Trade Center** | | |
| **Suite 1500** | **Suite 1500** | | |
| **Long Beach** | **Long Beach** | | |
| **California** | **California** | **90831** | **90831** |
| (Address of Principal Executive Offices) | (Address of Principal Executive Offices) | (Zip Code) | (Zip Code) |

---

**Registrant's Telephone Number, Including Area Code: (888) 848-4754** 

**27200 Tourney Road, Suite 200, Santa Clarita, California 91355**

**(Former Name or Former Address, if Changed Since Last Report)**

_____________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐&nbsp;&nbsp;&nbsp;&nbsp;Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐&nbsp;&nbsp;&nbsp;&nbsp;Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐&nbsp;&nbsp;&nbsp;&nbsp;Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐&nbsp;&nbsp;&nbsp;&nbsp;Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

---

| | | |
|:---|:---|:---|
| **Title of each class** | **Trading Symbol(s)** | **Name of each exchange on which registered** |
| Common Stock | CRC | New York Stock Exchange |

---

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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**Item 2.02&nbsp;&nbsp;&nbsp;&nbsp;Results of Operations and Financial Condition.**

On February 24, 2023, California Resources Corporation (the "Company") issued a press release announcing its financial condition and results of operations for the three and twelve months ended December 31, 2022. A copy of the press release is furnished as Exhibit 99.1 to this report on Form 8-K, and is incorporated herein by reference.

**Item 7.01&nbsp;&nbsp;&nbsp;&nbsp;Regulation FD Disclosure**

On February 24, 2023, the Company issued a press release announcing changes to its management team and certain other information. A copy of the press release is furnished as Exhibit 99.2 to this report on Form 8-K, and is incorporated herein by reference.

__________________________________________

The information contained in this report and the exhibits hereto shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, (the "Exchange Act"), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act, except as may be expressly set forth by specific reference in such filing.

Statements contained in the exhibits to this report that state the Company's or its management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions of the Securities Act and the Exchange Act. It is important to note that the Company's actual results could differ materially from those projected in such forward-looking statements. Factors that could affect these results include those mentioned in the documents that the Company has filed with the Securities and Exchange Commission (the "SEC").

The Company undertakes no duty or obligation to publicly update or revise the information contained in this report, although the Company may do so from time to time as management believes is warranted. Any such updating may be made through the filing of other reports or documents with the SEC, through press releases or through other public disclosure including disclosure in the Investor Relations portion of the Company's website.

**Item 9.01**&nbsp;&nbsp;&nbsp;&nbsp;**Financial Statements and Exhibits**

(d)&nbsp;&nbsp;&nbsp;&nbsp;Exhibits

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| | |
|:---|:---|
| **Exhibit No.** | **Description** |
| 99.1 | <u>[Press release dated](a2022q4erex991.htm)[February 2](a2022q4erex991.htm)[4](a2022q4erex991.htm)[, 202](a2022q4erex991.htm)[3](a2022q4erex991.htm)[.](a2022q4erex991.htm)</u> |
| 99.2 | <u>[Press release dated February 24, 2023.](a20230224exhibit992.htm)</u> |
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). |

---

------

**SIGNATURE**

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

---

| | |
|:---|:---|
| **California Resources Corporation** | **California Resources Corporation** |
| /s/ Michael L. Preston | /s/ Michael L. Preston |
| Name: | Michael L. Preston |
| Title: | Executive Vice President, Chief Strategy Officer and General Counsel |

---

DATED: February 24, 2023

## Exhibit 99.1

**Exhibit 99.1**

![crclogo_greenxgray-texta.jpg](crclogo_greenxgray-texta.jpg)

**NEWS RELEASE&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;** 

**<u>California Resources Corporation Generates Record $690 Million of Operating Cash Flow and $311 Million of Free Cash Flow in 2022, Raises its Share Repurchase Program by Nearly 30% to $1.1 Billion and Meaningfully Advances its Carbon Management Business</u>**

Long Beach, February 24, 2023 - 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."

**<u>Annual Highlights</u>**

&nbsp;&nbsp;&nbsp;&nbsp;• 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 income<sup>1</sup> was $384 million, or $4.95 per diluted share

&nbsp;&nbsp;&nbsp;&nbsp;• Generated operating cash flow of $690 million, adjusted EBITDAX<sup>1</sup> of $852 million, free cash flow<sup>1</sup> of $311 million, and E&P, Corporate and Other Free Cash Flow<sup>1</sup> of $362 million in 2022

&nbsp;&nbsp;&nbsp;&nbsp;• 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

&nbsp;&nbsp;&nbsp;&nbsp;• 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

&nbsp;&nbsp;&nbsp;&nbsp;• 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

&nbsp;&nbsp;&nbsp;&nbsp;• Advanced the Carbon Management Business in California on several fronts:

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Formed a joint venture with Brookfield Renewables,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Submitted Class VI permits to EPA for an additional 94 MMT of CO2 reservoirs,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Executed two CDMAs to sequester 470,000 MT of CO2 per annum at CTV I and CTV III reservoirs, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Made substantial progress on CalCapture Project with targeted Final Investment Decision (FID) in early 2024

&nbsp;&nbsp;&nbsp;&nbsp;• 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

**<u>Fourth Quarter 2022 Highlights</u>**

**<u>Financial</u>**

&nbsp;&nbsp;&nbsp;&nbsp;• 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 income<sup>1</sup> was $93 million, or $1.24 per diluted share

&nbsp;&nbsp;&nbsp;&nbsp;• Generated net cash provided by operating activities of $114 million, adjusted EBITDAX<sup>1</sup> of $208 million and free cash flow<sup>1</sup> of $39 million

&nbsp;&nbsp;&nbsp;&nbsp;• Ended the quarter with $307 million of cash on hand and an undrawn RBL credit facility representing $765 million of total liquidity<sup>2</sup>

&nbsp;&nbsp;&nbsp;&nbsp;• 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

&nbsp;&nbsp;&nbsp;&nbsp;• 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

**<u>Operations</u>**

&nbsp;&nbsp;&nbsp;&nbsp;• 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

&nbsp;&nbsp;&nbsp;&nbsp;• 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)

&nbsp;&nbsp;&nbsp;&nbsp;• Operated 36 maintenance rigs in the fourth quarter

**<u>2023 Guidance and Capital Program</u>**<sup>3</sup> 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 development<sup>4</sup>, $15 to $25 million of adjusted capital for carbon management projects<sup>4</sup> 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/d<sup>3</sup> (~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 GUIDANCE**<sup>3</sup> | **Total <br>2023E** | **CMB <br>2023E** | **E&P, Corp. & Other 2023E** |
| &nbsp;&nbsp;&nbsp;Net Total Production (MBoe/d) | 85 - 91 |  | 85 - 91 |
| &nbsp;&nbsp;&nbsp;Net Oil Production (MBbl/d) | 51 - 55 |  | 51 - 55 |
| &nbsp;&nbsp;&nbsp;Operating Costs ($ millions) | $845 - $895 |  | $845 - $895 |
| &nbsp;&nbsp;&nbsp;CMB Expenses<sup>5</sup> ($ millions) | $25 - $35 | $25 - $35 |  |
| &nbsp;&nbsp;&nbsp;Adjusted General and Administrative Expenses<sup>1</sup> ($ millions) | $195 - $225 | $10 - $15 | $185 - $210 |
| &nbsp;&nbsp;&nbsp;Total Capital ($ millions) | $200 - $245 | $5 - $15 | $195 - $230 |
| &nbsp;&nbsp;&nbsp;Adjusted Total Capital<sup>4</sup> ($ millions) | $200 - $245 | $15 - $25 | $185 - $220 |
| &nbsp;&nbsp;&nbsp; *Drilling & Completions* | *$66 - $76* |  | *$66 - $76* |
| &nbsp;&nbsp;&nbsp; *Workovers* | *$44 - $54* |  | *$44 - $54* |
| &nbsp;&nbsp;&nbsp; *Adjusted Facilities* | *$44 - $54* |  | *$44 - $54* |
| &nbsp;&nbsp;&nbsp; *Corporate & Other* | *$31 - $36* |  | *$31 - $36* |
| &nbsp;&nbsp;&nbsp; *Adjusted CMB* | *$15 - $25* | *$15 - $25* |  |
| &nbsp;&nbsp;&nbsp;Free Cash Flow<sup>1</sup> ($ millions) | $330 - $440 | ($60) - ($80) | $410 - $500 |
| &nbsp;&nbsp;&nbsp;Natural Gas Trading, Net ($ millions) | $60 - $70 |  | $60 - $70 |
| &nbsp;&nbsp;&nbsp;Net Electricity ($ millions) | $80 - $120 |  | $80 - $120 |
| &nbsp;&nbsp;&nbsp;Transportation Expense ($ millions) | $50 - $70 |  | $50 - $70 |
| &nbsp;&nbsp;&nbsp;ARO Settlement Payments\* ($ millions) | $55 - $60 |  | $55 - $60 |
| &nbsp;&nbsp;&nbsp;Taxes Other Than on Income\* ($ millions) | $175 - $185 |  | $175 - $185 |
| &nbsp;&nbsp;&nbsp;Interest and Debt Expense\* ($ millions) | $55 - $60 |  | $55 - $60 |
| &nbsp;&nbsp;&nbsp;Cash Income Taxes\* ($ millions) | $80 - $100 |  | $80 - $100 |
| &nbsp;&nbsp;&nbsp;Commodity Realizations: |  |  |  |
| &nbsp;&nbsp;&nbsp; Oil - % of Brent: | 97% - 99% |  | 97% - 99% |
| &nbsp;&nbsp;&nbsp; NGL - % of Brent: | 58% - 64% |  | 58% - 64% |
| &nbsp;&nbsp;&nbsp; Natural Gas - % of NYMEX: | 150% - 250% |  | 150% - 250% |
| &nbsp;&nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023 | &nbsp;&nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023 | &nbsp;&nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023 | &nbsp;&nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023 |

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**<u>First Quarter 2023 Guidance and Capital Program</u>**<sup>3</sup> 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/d<sup>3</sup> (~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 GUIDANCE**<sup>3</sup> | **Total <br>1Q23E** | **CMB <br>1Q23E** | **E&P, Corp. & Other 1Q23E** |
| &nbsp;&nbsp;&nbsp;Net Total Production (MBoe/d) | 89 - 91 |  | 89 - 91 |
| &nbsp;&nbsp;&nbsp;Net Oil Production (MBbl/d) | 53 - 54 |  | 53 - 54 |
| &nbsp;&nbsp;&nbsp;Operating Costs ($ millions) | $260 - $270 |  | $260 - $270 |
| &nbsp;&nbsp;&nbsp;CMB Expenses<sup>5</sup> ($ millions) | $5 - $10 | $5 - $10 |  |
| &nbsp;&nbsp;&nbsp;Adjusted General and Administrative Expenses<sup>1</sup> ($ millions) | $50 - $58 | $3 - $5 | $47 - $53 |
| &nbsp;&nbsp;&nbsp;Total Capital ($ millions) | $57 - $69 | $2 - $4 | $55 - $65 |
| &nbsp;&nbsp;&nbsp;Adjusted Total Capital<sup>4</sup> ($ millions) | $57 - $69 | $2 - $4 | $55 - $65 |
| &nbsp;&nbsp;&nbsp;Free Cash Flow<sup>1</sup> ($ millions) | $151 - $180 | ($15) - ($24) | $175 - $195 |
| &nbsp;&nbsp;&nbsp;Natural Gas Trading, Net ($ millions) | $35 - $45 |  | $35 - $45 |
| &nbsp;&nbsp;&nbsp;Net Electricity ($ millions) | $25 - $35 |  | $25 - $35 |
| &nbsp;&nbsp;&nbsp;Transportation Expense ($ millions) | $14 - $16 |  | $14 - $16 |
| &nbsp;&nbsp;&nbsp;Commodity Realizations: |  |  |  |
| &nbsp;&nbsp;&nbsp; Oil - % of Brent: | 97% - 99% |  | 97% - 99% |
| &nbsp;&nbsp;&nbsp; NGL - % of Brent: | 63% - 65% |  | 63% - 65% |
| &nbsp;&nbsp;&nbsp; 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. | \*Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. | \*Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. | \*Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. |

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**<u>Fourth Quarter & Full Year 2022 E&P Operational Results</u>**

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.

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**<u>Fourth Quarter & Full Year 2022 Financial Results</u>**

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| | | | | |
|:---|:---|:---|:---|:---|
| | **4th Quarter** | 3rd Quarter | **Total Year** | Total Year |
| ($ and shares in millions, except per share amounts) | **2022** | 2022 | **2022** | 2021 |
| **<u>Statements of Operations:</u>** |  |  |  |  |
| **Revenues** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Total operating revenues | $**682** | $1125 | $**2707** | $1889 |
| **Operating Expenses** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp; Total operating expenses | **549** | 536 | **1954** | 1720 |
| 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 income<sup>1</sup> | $**93** | $111 | $**384** | $506 |
| Adjusted net income<sup>1</sup> 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 EBITDAX<sup>1</sup> | $**208** | $234 | $**852** | $860 |

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**<u>Review of Fourth Quarter & Full Year 2022 Financial Results</u>**

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 EBITDAX<sup>1</sup> 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 flow<sup>1</sup> during the same periods.

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| | | | | |
|:---|:---|:---|:---|:---|
| **FREE CASH FLOW**<sup>1</sup> | | | | |
| 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). | 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). | 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). | 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). | 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 |
| &nbsp;&nbsp;&nbsp;&nbsp;Capital investments | **(75)** | (107) | **(379)** | (194) |
| Free cash flow<sup>1</sup> | **39** | 128 | **311** | 466 |
| E&P, corporate & other free cash flow<sup>1</sup> | $**61** | $139 | $**362** | $472 |
| CMB free cash flow<sup>1</sup> | $**(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** | **OPERATING COSTS PER BOE** | **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. | 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. | 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. | 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. | 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 |
| &nbsp;&nbsp;&nbsp;Excess costs attributable to PSCs | $**(1.90)** | (2.16) | $**(2.23)** | (1.83) |
| Operating costs, excluding effects of PSCs <sup>(a)</sup> | $**21.96** | $23.11 | $**21.52** | $17.56 |
| (a) Operating costs, excluding effects of PSCs is a non-GAAP measure. | (a) Operating costs, excluding effects of PSCs is a non-GAAP measure. | (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.

**<u>Sustainability & Carbon Management Update</u>**

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.

**<u>Balance Sheet and Liquidity Update</u>**

------

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.

**<u>Acquisitions and Divestitures</u>**

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.

**<u>Shareholder Return Strategy</u>**

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.

**<u>Reserves</u>**

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-10<sup>1</sup> value of $9.2 billion. These estimates were based on SEC pricing and the average realized prices for estimating CRC's PV-10<sup>1</sup> 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** | **PV-10 AND STANDARDIZED MEASURE** | **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: | 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: | 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 | December 31, 2022 |
| Standardized Measure of discounted future net cash flows | $| 6726 |
| Present value of future income taxes discounted at 10% | 2493 | 2493 |
| PV-10 of cash flows <sup>(\*)</sup> | $| 9219 |
| <sup>(\*)</sup> 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.  | <sup>(\*)</sup> 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.  | <sup>(\*)</sup> 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.  |

---

**<u>Upcoming Investor Conference Participation</u>**

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Credit Suisse Vail Summit on February 26 in Vail, CO

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• MS Global Energy and Power Conference on March 1 in New York, NY

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• CERAWeek 2023 on March 6 to 8 in Houston, TX

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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.

**<u>Conference Call Details</u>**

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.

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<sup>(1)</sup> 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.

<sup>(2)</sup> 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.

<sup>(3)</sup> 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.

<sup>(4)</sup> 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.

<sup>(5)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.

**<u>About California Resources Corporation</u>**

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.

**<u>Forward-Looking Statements</u>**

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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• fluctuations in commodity prices, including supply and demand considerations for CRC's products and services;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• government policy, war and political conditions and events, including the war in Ukraine and oil sanctions on Russia, Iran and others;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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

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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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the impact of inflation on future expenses and changes generally in the prices of goods and services;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in business strategy and CRC's capital plan;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• lower-than-expected production or higher-than-expected production decline rates;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the recoverability of resources and unexpected geologic conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• production-sharing contracts' effects on production and operating costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the lack of available equipment, service or labor price inflation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• limitations on transportation or storage capacity and the need to shut-in wells;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• any failure of risk management;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• results from operations and competition in the industries in which CRC operates;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• CRC's ability to realize the anticipated benefits from prior or future efforts to reduce costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the creditworthiness and performance of CRC's counterparties, including financial institutions, operating partners, CCS project participants and other parties;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• reorganization or restructuring of CRC's operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• CRC's ability to claim and utilize tax credits or other incentives in connection with its CCS projects,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• CRC's ability to realize the benefits contemplated by its energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• CRC's ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• uncertainty around the accounting of emissions and CRC's ability to successfully gather and verify emissions data and other environmental impacts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes to CRC's dividend policy and Share Repurchase Program, and its ability to declare future dividends or repurchase shares under its debt agreements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• limitations on CRC's financial flexibility due to existing and future debt;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• insufficient cash flow to fund CRC's capital plan and other planned investments and return capital to shareholders;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• effects of hedging transactions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the effect of CRC's stock price on costs associated with incentive compensation;

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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.

**<u>Contacts:</u>**

Joanna Park (Investor Relations) 818-661-3731 <br>Joanna.Park@crc.com Richard Venn (Media)818-661-6014<u>Richard.Venn@crc.com</u>

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---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Attachment 1** | **Attachment 1** | **Attachment 1** | **Attachment 1** | **Attachment 1** | **Attachment 1** |
| **SUMMARY OF RESULTS**<br>($ and shares in millions, except per share amounts) |<br>**4th Quarter**<br>**2022** |<br>**3rd Quarter**<br>**2022** |<br>**4th Quarter**<br>**2021** |<br>**Total Year**<br>**2022** |<br>**Total Year**<br>**2021** |
| **<u>Statements of Operations:</u>** |  |  |  |  |  |
| **Revenues** |  |  |  |  |  |
| Oil, natural gas and NGL sales | $**617** | $**680** | $**589** | $**2643** | $**2048** |
| 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** |
| &nbsp;&nbsp;&nbsp;&nbsp; Total operating revenues | **682** | **1125** | **634** | **2707** | **1889** |
| **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** |
| &nbsp;&nbsp;&nbsp;&nbsp; Total operating expenses | **549** | **536** | **422** | **1954** | **1720** |
| 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)%** |

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **GAINS AND LOSSES FROM COMMODITY DERIVATIVES** | **GAINS AND LOSSES FROM COMMODITY DERIVATIVES** | **GAINS AND LOSSES FROM COMMODITY DERIVATIVES** | **GAINS AND LOSSES FROM COMMODITY DERIVATIVES** | | |
| | **4th Quarter** | **3rd Quarter** | **4th Quarter** | | |
| ($ millions) | **2022** | **2022** | **2021** |<br>**Total Year**<br>**2022** |<br>**Total Year**<br>**2021** |
| &nbsp;&nbsp;&nbsp;Non-cash derivative gain (loss) | $**2** | $**425** | $**26** | $**187** | $**(357)** |
| &nbsp;&nbsp;&nbsp;&nbsp;Net payments on settled commodity contracts | **(134)** | **(182)** | **(99)** | **(738)** | **(319)** |
| &nbsp;&nbsp;&nbsp;&nbsp; Net (loss) gain from commodity derivatives | $**(132)** | $**243** | $**(73)** | $**(551)** | $**(676)** |

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| | | | | |
|:---|:---|:---|:---|:---|
| **1st Quarter** | 1st Quarter | **4th Quarter** | **4th Quarter** | 4th Quarter |

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **CAPITAL INVESTMENTS** | **CAPITAL INVESTMENTS** | **CAPITAL INVESTMENTS** | **CAPITAL INVESTMENTS** | | |
| | **4th Quarter** | **3rd Quarter** | **4th Quarter** | | |
| ($ millions) | **2022** | **2022** | **2021** |<br>**Total Year**<br>**2022** |<br>**Total Year**<br>**2021** |
| &nbsp;&nbsp;&nbsp;Facilities <sup>(1)</sup> | $**19** | $**20** | $14 | $**71** | $43 |
| &nbsp;&nbsp;&nbsp;Drilling | **48** | **73** | 46 | **242** | 119 |
| &nbsp;&nbsp;&nbsp;Workovers | **14** | **7** | 2 | **36** | 27 |
| Total E&P capital | 81 | 100 | 62 | 349 | 189 |
| &nbsp;&nbsp;&nbsp;CMB <sup>(1)(2)</sup> | **(13)** | **6** |  | **4** |  |
| &nbsp;&nbsp;&nbsp;Corporate and other | **7** | **1** | 4 | **26** | 5 |
| Total capital program | $**75** | $**107** | $**66** | $**379** | $**194** |
| <sup>(1)</sup>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.  | <sup>(1)</sup>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.  | <sup>(1)</sup>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.  | <sup>(1)</sup>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.  | <sup>(1)</sup>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.  | <sup>(1)</sup>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.  |
| <sup>(2)</sup> In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.  | <sup>(2)</sup> In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.  | <sup>(2)</sup> In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.  | <sup>(2)</sup> In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.  | <sup>(2)</sup> In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.  | <sup>(2)</sup> In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets.  |

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| |
|:---|
| **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.  |

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **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. | 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. | 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. | 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. | 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. | 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: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Non-cash derivative (gain) loss | **(2)** | **(425)** | **(26)** | **(187)** | **357** |
| &nbsp;&nbsp;&nbsp;Asset impairments | **—** | **—** | **—** | **2** | **28** |
| &nbsp;&nbsp;&nbsp;Reorganization items, net | **—** | **—** | **1** | **—** | **6** |
| &nbsp;&nbsp;&nbsp;Severance and termination costs | **—** | **—** | **—** | **—** | **15** |
| &nbsp;&nbsp;&nbsp;Net loss on early extinguishment of debt | **—** | **—** | **—** | **—** | **2** |
| &nbsp;&nbsp;&nbsp;Net loss (gain) on asset divestitures | **1** | **(2)** | **(120)** | **(59)** | **(124)** |
| &nbsp;&nbsp;&nbsp;Rig termination expenses | **2** | **—** | **—** | **2** | **2** |
| &nbsp;&nbsp;&nbsp;Other, net | **13** | **4** | **2** | **20** | **4** |
| &nbsp;&nbsp;&nbsp;&nbsp;Total unusual, infrequent and other items | **14** | **(423)** | **(143)** | **(222)** | **290** |
| &nbsp;&nbsp;&nbsp;Income tax (benefit) provision of adjustments at effective tax rate | **(4)** | **120** | **—** | **63** | **—** |
| &nbsp;&nbsp;&nbsp;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** |

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **ADJUSTED EBITDAX** | **ADJUSTED EBITDAX** | **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. <br>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). | 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. <br>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). | 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. <br>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). | 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. <br>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). | 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. <br>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). | 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. <br>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** |
| &nbsp;&nbsp;&nbsp;Interest and debt expense | **14** | **13** | **14** | **53** | **54** |
| &nbsp;&nbsp;&nbsp;Depreciation, depletion and amortization | **49** | **50** | **53** | **198** | **213** |
| &nbsp;&nbsp;&nbsp;Income tax provision (benefit) | **34** | **153** | **(396)** | **237** | **(396)** |
| &nbsp;&nbsp;&nbsp;Exploration expense | **1** | **1** | **1** | **4** | **7** |
| &nbsp;&nbsp;&nbsp;Interest income | **(3)** | **(1)** | **—** | **(4)** | **—** |
| &nbsp;&nbsp;&nbsp;Unusual, infrequent and other items <sup>(1)</sup> | **14** | **(423)** | **(143)** | **(222)** | **290** |
| &nbsp;&nbsp;&nbsp;Non-cash items |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp; Accretion expense | **11** | **10** | **11** | **43** | **50** |
| &nbsp;&nbsp;&nbsp; Stock-based compensation | **4** | **5** | **4** | **17** | **14** |
| &nbsp;&nbsp;&nbsp; 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** |
| &nbsp;&nbsp;&nbsp;Cash interest payments | **2** | **23** | **2** | **50** | **31** |
| &nbsp;&nbsp;&nbsp;Cash interest received | **(3)** | **(1)** | **—** | **(4)** | **—** |
| &nbsp;&nbsp;&nbsp;Cash income taxes | **—** | **—** | **—** | 20 | **—** |
| &nbsp;&nbsp;&nbsp;Exploration expenditures | **1** | **1** | **1** | **4** | **7** |
| &nbsp;&nbsp;&nbsp;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** |
| <sup>(1)</sup> See Adjusted Net Income (Loss) reconciliation. |  |  |  |  |  |

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **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). <br>CRC has also excluded bankruptcy related fees during 2021 as a supplemental measure of its 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). <br>CRC has also excluded bankruptcy related fees during 2021 as a supplemental measure of its 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). <br>CRC has also excluded bankruptcy related fees during 2021 as a supplemental measure of its 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). <br>CRC has also excluded bankruptcy related fees during 2021 as a supplemental measure of its 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). <br>CRC has also excluded bankruptcy related fees during 2021 as a supplemental measure of its 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). <br>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)** | $**—** |

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES** | **ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES** | **ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES** | **ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES** | **ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES** | **ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES** | **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 or 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). | 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 or 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). | 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 or 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). | 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 or 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). | 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 or 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). | 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 or 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). | 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 or 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** | 43 | $**48** | $**49** | $**189** | $**186** |
| CMB Adjusted G&A expenses | $**2** |  | $**5** | $**—** | $**12** | $**—** |
| **OPERATING COSTS PER BOE** | **OPERATING COSTS PER BOE** | **OPERATING COSTS PER BOE** | **OPERATING COSTS PER BOE** | **OPERATING COSTS PER BOE** | **OPERATING COSTS PER BOE** | **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. | 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. | 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. | 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. | 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. | 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. | 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 <sup>(1)</sup> | $**9.56** |  | $**10.96** | $**8.04** | $**9.76** | $**7.01** |
| Gas processing costs <sup>(2)</sup> | **0.48** |  | **0.49** | **0.41** | **0.52** | **0.54** |
| Non-energy operating costs <sup>(3)</sup> | **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 |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Excess energy operating costs attributable to PSCs | $**(0.76)** |  | $**(0.97)** | $**(0.82)** | $**(0.92)** | $**(0.68)** |
| &nbsp;&nbsp;&nbsp;&nbsp;Excess non-energy operating costs attributable to PSCs | **(1.14)** |  | **(1.19)** | **(1.31)** | **(1.31)** | **(1.15)** |
| &nbsp;&nbsp;&nbsp; **Excess costs attributable to PSCs** | $**(1.90)** |  | $**(2.16)** | $**(2.13)** | $**(2.23)** | $**(1.83)** |
| &nbsp;&nbsp;&nbsp;Energy operating costs, excluding effect of PSCs <sup>(1)</sup> | $**8.80** |  | $**9.99** | $**7.22** | $**8.84** | $**6.33** |
| &nbsp;&nbsp;&nbsp;Gas processing costs, excluding effect of PSCs <sup>(2)</sup> | **0.48** |  | **0.49** | **0.41** | **0.52** | **0.54** |
| &nbsp;&nbsp;&nbsp;Non-energy operating costs, excluding effect of PSCs <sup>(3)</sup> | **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** |
| <sup>(1)</sup> 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. | <sup>(1)</sup> 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. | <sup>(1)</sup> 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. | <sup>(1)</sup> 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. | <sup>(1)</sup> 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. | <sup>(1)</sup> 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. | <sup>(1)</sup> 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. |
| <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | <sup>(2)</sup> Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. |
| <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. |

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|:---|:---|:---|:---|:---|:---|
| **Attachment 3** | **Attachment 3** | **Attachment 3** | **Attachment 3** | **Attachment 3** | **Attachment 3** |
| **PRODUCTION STATISTICS**<br>**Net Production Per Day** |<br>**4th Quarter**<br>**2022** |<br>**3rd Quarter**<br>**2022** |<br>**4th Quarter**<br>**2021** |<br>**Total Year**<br>**2022** |<br>**Total Year**<br>**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. | 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. | 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. | 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. | 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. | 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. |

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|:---|:---|:---|:---|:---|:---|
| | | | | | **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%** |

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|:---|:---|:---|:---|:---|:---|
| | | | | | **Attachment 5** |
| **FOURTH QUARTER 2022 DRILLING ACTIVITY**<br>**Wells Drilled** |<br>**San Joaquin**<br>**Basin** |<br>**Los Angeles**<br>**Basin** |<br>**Ventura**<br>**Basin** |<br>**Sacramento**<br>**Basin** |<br>**Total** |
| **Development Wells** | | | | | |
| &nbsp;&nbsp;&nbsp;Primary | 1 |  |  |  | 1 |
| &nbsp;&nbsp;&nbsp;Waterflood |  | 16 |  |  | 16 |
| &nbsp;&nbsp;&nbsp;Steamflood | 6 |  |  |  | 6 |
| **Total** <sup>(1)</sup> | 7 | 16 |  |  | 23 |
| **TOTAL YEAR 2022 DRILLING ACTIVITY** |  |  |  |  |  |
|  | **San Joaquin** | **Los Angeles** | **Ventura** | **Sacramento** |  |
| **Wells Drilled** | **Basin** | **Basin** | **Basin** | **Basin** | **Total** |
| **Development Wells** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Primary | 18 |  |  |  | 18 |
| &nbsp;&nbsp;&nbsp;Waterflood | 27 | 41 |  |  | 68 |
| &nbsp;&nbsp;&nbsp;Steamflood | 61 |  |  |  | 61 |
| **Total** <sup>(1)</sup> | 106 | 41 |  |  | 147 |
| <sup>(1)</sup> Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | <sup>(1)</sup> Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | <sup>(1)</sup> Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | <sup>(1)</sup> Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | <sup>(1)</sup> Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. |  |

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | | | **Attachment 6** | **Attachment 6** |
| **OIL HEDGES AS OF DECEMBER 31, 2022** |<br>**Q1 2023** |<br>**Q2 2023** |<br>**Q3 2023** |<br>**Q4 2023** | **2024** |
| **Sold Calls** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Barrels per day | 18322 | 17837 | 17363 | 5747 |  |
| &nbsp;&nbsp;&nbsp;Weighted-average Brent price per barrel | $57.28 | $60.00 | $57.06 | $57.06 |  |
| **Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Barrels per day | 16620 | 16475 | 16697 | 26094 | 1492 |
| &nbsp;&nbsp;&nbsp;Weighted-average Brent price per barrel | $69.46 | $68.53 | $68.33 | $70.18 | $79.06 |
| **Net Purchased Puts** <sup>(1)</sup> |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Barrels per day | 18322 | 17837 | 17363 | 5747 | 1724 |
| &nbsp;&nbsp;&nbsp;Weighted-average Brent price per barrel | $76.25 | $76.25 | $76.25 | $76.25 | $75.00 |
| <sup>(1)</sup> Purchased puts and sold puts with the same strike price have been presented on a net basis. | <sup>(1)</sup> Purchased puts and sold puts with the same strike price have been presented on a net basis. | <sup>(1)</sup> Purchased puts and sold puts with the same strike price have been presented on a net basis. | <sup>(1)</sup> Purchased puts and sold puts with the same strike price have been presented on a net basis. | <sup>(1)</sup> Purchased puts and sold puts with the same strike price have been presented on a net basis. | <sup>(1)</sup> Purchased puts and sold puts with the same strike price have been presented on a net basis. |

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| | | | |
|:---|:---|:---|:---|
| | | | **Attachment 7** |
| | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** |
|<br>**TOTAL CRC GUIDANCE**<sup>1</sup> | **Consolidated** | **CMB** | **E&P, Corporate & Other** |
| &nbsp;&nbsp;&nbsp;Net Total Production (MBoe/d) | 85 - 91 |  | 85 - 91 |
| &nbsp;&nbsp;&nbsp;Net Oil Production (MBbl/d) | 51 - 55 |  | 51 - 55 |
| &nbsp;&nbsp;&nbsp;Operating Costs ($ millions) | $845 - $895 |  | $845 - $895 |
| &nbsp;&nbsp;&nbsp;CMB Expenses<sup>2</sup> ($ millions) | $25 - $35 | $25 - $35 |  |
| &nbsp;&nbsp;&nbsp;Adjusted General and Administrative Expenses ($ millions) | $195 - $225 | $10 - $15 | $185 - $210 |
| &nbsp;&nbsp;&nbsp;Total Capital ($ millions) | $200 - $245 | $5 - $15 | $195 - $230 |
| &nbsp;&nbsp;&nbsp;Adjusted Total Capital<sup>3</sup> ($ millions) | $200 - $245 | $15 - $25 | $185 - $220 |
| &nbsp;&nbsp;&nbsp;Free Cash Flow ($ millions) | $330 - $440 | ($60) - ($80) | $410 - $500 |
| &nbsp;&nbsp;&nbsp;Natural Gas Trading, Net ($ millions) | $60 - $70 |  | $60 - $70 |
| &nbsp;&nbsp;&nbsp;Net Electricity ($ millions) | $80 - $120 |  | $80 - $120 |
| &nbsp;&nbsp;&nbsp;Transportation Expense ($ millions) | $50 - $70 |  | $50 - $70 |
| &nbsp;&nbsp;&nbsp;ARO Settlement Payments\* ($ millions) | $55 - $60 |  | $55 - $60 |
| &nbsp;&nbsp;&nbsp;Taxes Other Than on Income\* ($ millions) | $175 - $185 |  | $175 - $185 |
| &nbsp;&nbsp;&nbsp;Interest and Debt Expense\* ($ millions) | $55 - $60 |  | $55 - $60 |
| &nbsp;&nbsp;&nbsp;Cash Income Taxes\* ($ millions) | $80 - $100 |  | $80 - $100 |
| &nbsp;&nbsp;&nbsp;Commodity Realizations: |  |  |  |
| &nbsp;&nbsp;&nbsp; Oil - % of Brent: | 97% - 99% |  | 97% - 99% |
| &nbsp;&nbsp;&nbsp; NGL - % of Brent: | 58% - 64% |  | 58% - 64% |
| &nbsp;&nbsp;&nbsp; Natural Gas - % of NYMEX\*: | 150% - 250% |  | 150% - 250% |
| &nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023<br>&nbsp;&nbsp;&nbsp;&nbsp;• Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. | &nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023<br>&nbsp;&nbsp;&nbsp;&nbsp;• Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. | &nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023<br>&nbsp;&nbsp;&nbsp;&nbsp;• Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. | &nbsp;&nbsp;&nbsp;\*Notes:<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q and 4Q, respectively<br>&nbsp;&nbsp;&nbsp;&nbsp;• 2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q, respectively <br>&nbsp;&nbsp;&nbsp;&nbsp;• Cash Income Taxes aren't paid evenly throughout 2023<br>&nbsp;&nbsp;&nbsp;&nbsp;• Note: January and February natural gas average realized prices were ~$47.50 and ~$10.00 per Mcf, respectively. |

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| | | | |
|:---|:---|:---|:---|
| | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** |
|<br>**Total CRC GUIDANCE**<sup>1</sup> | **Consolidated** | **CMB** | **E&P, Corporate & Other** |
| &nbsp;&nbsp;&nbsp;Net Total Production (MBoe/d) | 89 - 91 |  | 89 - 91 |
| &nbsp;&nbsp;&nbsp;Net Oil Production (MBbl/d) | 53 - 54 |  | 53 - 54 |
| &nbsp;&nbsp;&nbsp;Operating Costs ($ millions) | $260 - $270 |  | $260 - $270 |
| &nbsp;&nbsp;&nbsp;CMB Expenses<sup>2</sup> ($ millions) | $5 - $10 | $5 - $10 |  |
| &nbsp;&nbsp;&nbsp;Adjusted General and Administrative Expenses ($ millions) | $50 - $58 | $3 - $5 | $47 - $53 |
| &nbsp;&nbsp;&nbsp;Total Capital ($ millions) | $57 - $69 | $2 - $4 | $55 - $65 |
| &nbsp;&nbsp;&nbsp;Adjusted Total Capital<sup>3</sup> ($ millions) | $57 - $69 | $2 - $4 | $55 - $65 |
| &nbsp;&nbsp;&nbsp;Free Cash Flow ($ millions) | $151 - $180 | ($15) - ($24) | $175 - $195 |
| &nbsp;&nbsp;&nbsp;Natural Gas Trading, Net ($ millions) | $35 - $45 |  | $35 - $45 |
| &nbsp;&nbsp;&nbsp;Net Electricity ($ millions) | $25 - $35 |  | $25 - $35 |
| &nbsp;&nbsp;&nbsp;Transportation Expense ($ millions) | $14 - $16 |  | $14 - $16 |
| &nbsp;&nbsp;&nbsp;Commodity Realizations: |  |  |  |
| &nbsp;&nbsp;&nbsp; Oil - % of Brent: | 97% - 99% |  | 97% - 99% |
| &nbsp;&nbsp;&nbsp; NGL - % of Brent: | 63% - 65% |  | 63% - 65% |
| &nbsp;&nbsp;&nbsp; Natural Gas - % of NYMEX: | 400% - 500% |  | 400% - 500% |

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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**

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** |
| | **Consolidated** | **Consolidated** | **CMB** | **CMB** | **E&P, Corporate & Other** | **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 investments<sup>3</sup> | (245) | (200) | (25) | (15) | (220) | (185) |
| **Estimated free cash flow** | $330 | $440 | $(80) | $(60) | $410 | $500 |
|  | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** |
|  | **Consolidated** | **Consolidated** | **CMB** | **CMB** | **E&P, Corporate & Other** | **E&P, Corporate & Other** |
| *($ 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 |

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**ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION** 

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** | **2023 Estimated** |
| | **Consolidated** | **Consolidated** | **CMB** | **CMB** | **E&P, Corporate & Other** | **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 | $210 |
|  | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** | **1Q23 Estimated** |
|  | **Consolidated** | **Consolidated** | **CMB** | **CMB** | **E&P, Corporate & Other** | **E&P, Corporate & Other** |
| *($ 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 |
| <sup>(1)</sup> 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.  | <sup>(1)</sup> 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.  | <sup>(1)</sup> 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.  | <sup>(1)</sup> 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.  | <sup>(1)</sup> 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.  | <sup>(1)</sup> 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.  | <sup>(1)</sup> 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.  |
| <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  | <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  | <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  | <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  | <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  | <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  | <sup>(2)</sup> CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.  |
| <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. | <sup>(3)</sup> 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. |

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## Exhibit 99.2

**EXHIBIT 99.2**

![image_0a.jpg](image_0a.jpg)

**NEWS RELEASE**

**California Resources Corporation Initiates Strategic Realignment of Business Operations and Corporate Structure to Maximize Cash Flow Per Share**

*Francisco J. Leon to Succeed Mark A. McFarland as President and Chief Executive Officer* 

*McFarland to Continue as a Non-Executive Director and Chair the Board of Carbon TerraVault, CRC's Carbon Management Business, to Oversee its Continued Growth*

LONG BEACH, Calif., Feb. 24, 2023 – California Resources Corporation (NYSE: CRC) ("CRC" or the "Company") announced today a strategic realignment of the Company's business operations and structure. The Company intends to reduce costs to align with activity levels, increase its financial flexibility and optimize its portfolio of assets. The Company believes that the combination of these actions will allow it to continue to strengthen shareholder returns. The Company is also repositioning the business to capitalize on future opportunities with Carbon TerraVault. In conjunction with this strategic realignment, the Company also announced that Francisco Leon, currently Chief Financial Officer, will succeed Mark A. ("Mac") McFarland as President and Chief Executive Officer and join the Company's Board of Directors, effective at the Company's 2023 Annual Meeting in April.

"As demonstrated by our 2022 year-end financial results, CRC has a very resilient and valuable portfolio of assets," Mr. Leon said. "While the Company's financial performance has been strong, our market has evolved and therefore we are adjusting accordingly by optimizing our capital plan and increasing our focus on reducing costs. We believe our revised plan will enhance shareholder returns while positioning the Company for continued success into the future."

The revised plan realigns CRC's operating strategy while adjusting the Company's corporate and management structure as set forth below:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• Revised Corporate Structure -** CRC will adjust its corporate operating structure to facilitate the separate operations of its E&P and carbon management businesses. This change will allow investors and other CRC stakeholders to garner a better awareness and understanding of the Company's discrete businesses as CRC's leadership continues efforts to maximize shareholder value across the portfolio of assets.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• Accelerate Carbon Management Business -** CRC will manage its carbon management business on a standalone basis over time, providing the flexibility to consider strategic options including a potential separation from the E&P business. This is a natural evolution given the great strides made in 2022, including the formation of Carbon TerraVault's joint venture with Brookfield Renewable. The joint venture was formed to create a partnership focused on carbon capture and sequestration development, along with carbon management service agreements with parties such as Lone Cypress Energy and Grannus, LLC, to provide permanent carbon storage. In 2023, CRC is focused on signing up additional emitter projects, advancing CalCapture and the California Direct Air Capture Hub, and submitting additional Class VI permit applications. CRC has also established a separate board for the Carbon TerraVault subsidiary to focus on growing and developing the carbon management business.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• Leadership Changes -** With the revised corporate structure, Mr. Leon will assume the CEO position, effective at the Company's Annual Meeting. As CFO, Mr. Leon has been instrumental in the creation of the Company's carbon management business. He also has a deep knowledge and understanding of CRC's extensive E&P business. As such, Mr. Leon is extremely well positioned to lead CRC in the years ahead. In May, Mr. McFarland will transition to his former role as a non-executive director and will also serve as non-executive Chair of the newly formed Board of the Carbon TerraVault subsidiary. Two existing CRC non-executive directors, Andrew Bremner and James Chapman, will also serve on that subsidiary board. The Company has an ongoing search for a new CFO.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• **Future E&P Development Activity -** The Company will reduce its rig count to 1.5 in 2023 with a drilling program focused on developing the highest-returning projects with permits-in-hand in conjunction with a continued focus on well servicing and downhole maintenance to reduce the base production decline to approximately 5 to 7 percent. At the planned rig pace, CRC can enhance the operational and capital efficiency of its rig program and maximize the Company's ability to return capital to shareholders. On a go-forward basis utilizing a 1.5 rig program, CRC expects 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 anticipated to be funded by projected CTV JV contributions over time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• Focus on Cost Reductions and Value Enhancing Portfolio Optimizations –** CRC's leadership team, working closely with the Special Finance Committee of the Board, is focused on cost reduction initiatives across the Company that align with the projected level of activity and revised strategic direction. CRC is targeting a 5% - 10% reduction in non- energy operating costs (excluding downhole maintenance) and Adj. E&P Corp & Other G&A<sup>1</sup> on a combined basis by year end. These cost reduction initiatives in conjunction with increased downhole maintenance target maintaining margins and driving higher cash flows. CRC's leadership team and Board have successfully implemented similar strategies and believe the Company is well positioned to identify and achieve cost reductions while maintaining the high operational standards that CRC has achieved. In addition, CRC will continue to pursue the monetization of its Huntington Beach surface acreage as well as other real estate surface ownership in its portfolio.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• Enhance the Company's Financial Flexibility -** CRC is intending to amend and extend or replace its existing reserve-based lending credit facility, as well as refinance its $600 million senior unsecured notes. This is expected to allow the Company to lengthen its debt maturities and provide financial flexibility to increase the Company's ongoing shareholder return program. Further, this flexibility is expected to support the potential separation of the carbon management business. Finally, operating Carbon TerraVault on a standalone basis will broaden capital sourcing options for the carbon management business.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• Boost Shareholder Return Program -** CRC intends to optimize capital allocation and focus on cost reduction opportunities in 2023 to drive cash flow generation that it believes will allow it to increase shareholder returns. To that end, CRC's Board has authorized a nearly 30% increase to its shareholder repurchase program for a total of $1.1 billion, with ~$640 million remaining on its authorization as of December 31, 2022, and after taking account the increase. In 2023, CRC is positioning to return approximately 100% of free cash flow through buybacks and dividends.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**• CRC's strategy is repeatable with a focus on maximizing cash flow per share -** So long as the current conditions persist, the Company expects to repeat its strategy. This means continuously focusing its activity on locations where the Company has permits in hand, re-aligning costs with activity levels and maintaining its financial flexibility. CRC believes that the repeatable nature of the strategy will allow the Company to continue prioritizing returning cash to shareholders through share repurchases and dividends.

"I am honored to assume the CEO role," Mr. Leon said. "Over the last few years, the Company has significantly improved its financial profile and optimized its operating portfolio, providing a strong foundation for growth and value creation. Now, as we face new opportunities and challenges, I look forward to working with Mac and the rest of the Board and management team to execute on our new strategic direction to drive cash flow generation, advance and accelerate our carbon management business, and increase our financial flexibility to return more capital to shareholders. I am confident that if we continue to elect to run a lower capital plan (~$155 million of drilling and completion capital) we can make the appropriate reductions to our cost structure that we expect will help ensure we deliver improving operating and financial metrics on a per share basis."

"I am extremely proud of all that our talented team has accomplished over the past two years, successfully transforming the Company into a lean and efficient operator with robust cash flows," Mr. McFarland said. "We achieved these results while launching an exciting new business in carbon management." He continued,

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"Francisco has been a fabulous partner, with extensive knowledge of CRC's E&P business while being instrumental in the creation of our carbon business. As such, he is uniquely positioned to lead the Company in its next phase of strategic development."

"While Mac is stepping down from a day-to-day role at CRC, I look forward to working closely with him as a CRC board member and in his role as Chair of the Board of Carbon TerraVault to accelerate CRC's carbon management business and help California achieve its ambitious energy transition goals," said TJ Thom Cepak, Chair of the Company's Board of Directors.

In a separate release today, the Company disclosed its fourth quarter and full year 2022 financial results. The Company will host a conference call with investors and analysts today at 10:00 a.m. PT / 1:00 p.m. ET to review its financial results.

(1)Represents a non-GAAP measure. For all historical non-GAAP financial measures for CRC please see the Investor Relations page at www.crc.com for a reconciliation to the nearest GAAP equivalent and other additional information. See slide 35 of CRC's 4Q22 earnings presentation for reconciliation.

**About Francisco J. Leon** 

Francisco Leon has served as EVP and CFO of California Resources Corporation since 2020. From 2014 to 2020, he was VP of Business Development, Portfolio Management and Strategic Planning at CRC. He also served as Director of Global Acquisitions and California Resource Assessment / Evaluation at Occidental Petroleum. He began his career at Petrie Parkman in 2001. Mr. Leon holds a bi-national Bachelor of Arts degree in International Business from San Diego State University and CETYS Universidad in Mexico and an Masters of Business Administration from the University of Texas McCombs School of Business.

**About Mark A. (Mac) McFarland**

Mr. McFarland has served as President and Chief Executive Officer of California Resources Corporation since March 2021 and has served on its Board of Directors since October 2020. Beginning in October 2020, he served as Chairman and then Executive Chair of the Board and interim Chief Executive Officer prior to his appointment as President and Chief Executive Officer in March 2021. He previously served as Executive Chairman of GenOn Energy, Inc., an independent power producer, and currently serves as a Director on the Company's Board. Prior to that, he was the President and Chief Executive Officer of GenOn and served on its Board of Managers. Mr. McFarland served in a succession of management roles, including Chief Executive Officer, Chief Commercial Officer and Executive Vice President, Corporate Development and Strategy of Energy Future Holdings, at Luminant Holding Company, a subsidiary of Energy Future Holdings Corporation, and a large independent power producer. Earlier in his career, Mr. McFarland served in various roles at Exelon Corporation, including as Senior Vice President, Corporate Development. Mr. McFarland earned his Masters of Business Administration from the University of Delaware and a Bachelor of Science degree in Civil Engineering (Environmental Concentration) from Virginia Polytechnic Institute and State University.

**About California Resources Corporation (CRC)**

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 its land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit <u>www.crc.com</u>.

**About Carbon TerraVault (CTV)**

Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, will provide services that include the capture, transport and storage of carbon dioxide for its customers. CTV is engaged in developing a series of CCS projects that inject carbon dioxide (CO2) captured from industrial sources into depleted underground reservoirs and permanently store CO2 deep underground. For more information about CTV, please visit <u>www.carbonterravault.com</u>.

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**Forward-Looking Statements**

Certain of the statements contained in this document should be considered forward-looking statements. These forward-looking statements may be identified by words such as "may," "will," "expect," "intend," "anticipate," "believe," "estimate," "plan," "project," "could," "should," "would," "continue," "seek," "target," "guidance," "outlook," "forecast" and other similar words. Such statements include, but are not limited to, statements about the actions the Company may take to realign its strategy, the Company's ability to reduce permitting uncertainty, the implications of the Company's leadership changes, the Company's ability to amend its debt agreements and strengthen its financial flexibility, the growth of the Company's carbon management business, the Company's shareholder return program, the Company's plans, objectives, expectations, intentions, estimates and strategies for the future, and other statements that are not historical facts. These forward-looking statements are based on the Company's current objectives, beliefs and expectations, and they are subject to significant risks and uncertainties that may cause actual results and financial position and timing of certain events to differ materially from the information in the forward-looking statements. These risks and uncertainties include, but are not limited to, legislative or regulatory changes; availability or timing of, or conditions imposed on, permits and approvals; changes in business strategy and the Company's capital plan; the Company's ability to realize the benefits contemplated by the business strategies and initiatives related to energy transaction, including carbon capture and storage projects and other renewable energy efforts; the Company'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; changes in the Company's share repurchase program and its ability to repurchase shares under its debt agreements; insufficient cash flow to fund the Company's capital plan and other planned investments, stock repurchases and dividends; and the other risks and uncertainties set forth in the Company's Annual Report on Form 10-K for the year ended December 31, 2022 (especially in Part I, Item 1A. Risk Factors and Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations) and in the Company's other filings with the SEC. There may be other factors of which the Company is not currently aware that may affect matters discussed in the forward-looking statements and may also cause actual results to differ materially from those discussed. The Company does not assume any obligation to publicly update or supplement any forward-looking statement to reflect actual results, changes in assumptions or changes in other factors affecting these forward-looking statements other than as required by law. Any forward-looking statements speak only as of the date hereof or as of the dates indicated in the statement.

Joanna Park

Investor Relations

818-661-3731

<u>Joanna.Park@crc.com</u>

Richard Venn

Media

818-661-6014

<u>Richard.Venn@crc.com</u>

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