Form 8-K California Resources For: Aug 03
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E-mailUNITED 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): August 3, 2022
_____________________
(Exact Name of Registrant as Specified in its Charter)
| (State or Other Jurisdiction of Incorporation) | (Commission File Number) | (IRS Employer Identification No.) | |||||||||
| (Address of Principal Executive Offices) | (Zip Code) | ||||||||||
Registrant’s Telephone Number, Including Area Code: (888 ) 848-4754
N/A
(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:
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
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. ☐
Item 2.02. Results of Operations and Financial Condition.
On August 3, 2022, California Resources Corporation (“CRC”) issued a press release (the “Press Release”) announcing its financial condition and results of operations for the three and six months ended June 30, 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. Regulation FD Disclosure.
In the Press Release, CRC also announced the transaction described in Item 8.01 below. See the above-described press release furnished as Exhibit 99.1 to this report on Form 8-K, which is incorporated herein by reference.
The information furnished in this report (including in Item 2.02) shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended (the “Securities Act”), regardless of any general incorporation language in such filing, except as shall be expressly set forth by specific reference in such filing.
Statements contained in the exhibit to this report (including in Item 2.02) that state CRC’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 CRC’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 CRC has filed with the Securities and Exchange Commission (the “SEC”).
CRC undertakes no duty or obligation to publicly update or revise the information contained in this report, although CRC 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 CRC’s website.
Item 8.01. Other Events.
On August 3, 2022, CRC, acting through its subsidiaries, entered into a Joint Venture and Investment Agreement, and a series of other agreements, with BGTF Sierra Aggregator LLC (“Brookfield”) to form a joint venture for the development of a carbon management business in California, including to develop projects for the capture, transfer and/or storage of carbon dioxide. The joint venture will initially be conducted through four newly created joint venture entities: (i) Carbon TerraVault JV HoldCo, LLC (“JV HoldCo”), (ii) Carbon TerraVault JV Storage Company, LLC (“Storage Company”), (iii) Carbon TerraVault JV Infrastructure Company, LLC (“Infrastructure Company”) and (iv) Carbon TerraVault JV Storage Company Sub 1, LLC (“Storage Company Sub 1”). Storage Company and Infrastructure Company will be wholly owned by JV HoldCo. Storage Company will build, install, operate and maintain CO2 storage facilities. Infrastructure Company will build, install, operate and maintain CO2 capture equipment and transportation assets, and may provide funding as projects develop. Storage Company Sub 1, a wholly owned subsidiary of Storage Company, holds rights to inject CO2 into CRC’s 26R reservoir in the Elk Hills Field for permanent CO2 storage. Brookfield will acquire a 49% interest in JV HoldCo in exchange for an initial investment of $137 million, payable in three equal installments upon completion of certain milestones. The first installment of $45.7 million was funded on August 3, 2022. Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the joint venture, inclusive of the initial $137 million investment. The joint venture is targeting the injection of 5 million metric tons per annum and 200 million metric tons of total CO2 storage development. Brookfield could additionally invest over $1 billion in the strategic partnership assuming it fully participates in these projects. CRC will provide operational and support services to JV HoldCo.
1
Item 9.01 Financial Statements and Exhibits
(d) Exhibits
| Exhibit No. | Description | |||||||
| 99.1 | ||||||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | |||||||
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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 | |||||||||||
| /s/ Michael L. Preston | |||||||||||
| Name: | Michael L. Preston | ||||||||||
| Title: | Executive Vice President, Chief Administrative Officer and General Counsel | ||||||||||
DATED: August 3, 2022
NEWS RELEASE
California Resources Corporation Announces the Formation of a California Carbon Management Partnership with Brookfield Renewable, Reports Strong Second Quarter 2022 Results and Increases Full Year 2022 Free Cash Flow1 Guidance
Long Beach, August 3, 2022 - California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today announced the formation of a joint venture (the "JV") with Brookfield Renewable ("Brookfield"), creating a carbon management partnership focused on carbon capture and sequestration (“CCS”) development and reported second quarter 2022 operational and financial results.
Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the JV. The investment from Brookfield will be allocated through the Brookfield Global Transition Fund (“BGTF”), the world’s largest fund dedicated to facilitating the global transition to a net zero carbon economy. Brookfield, together with its institutional partners, will participate in the joint venture through BGTF. The first CCS project designated for development is CRC’s 26R reservoir in the Elk Hills Field which was contributed to the partnership at a value of $10 per metric ton, which will be paid in three installments with the last two installments subject to achievement of specific milestones. The initial Brookfield commitment provides CRC with additional capital to advance the Company's carbon management strategy, de-risks its CCS projects and aims to significantly progress the decarbonization of California. The JV is targeting the injection of 5 million metric tons per annum and 200 million metric tons of total carbon dioxide ("CO2") storage development, aligned with CRC’s 2027 goals. Reaching this target would require an estimated $2.5 billion of total capital, and Brookfield could make additional investments of more than $1 billion in the strategic partnership assuming it fully participates in these CCS projects.
The strategic partnership will benefit substantially from CRC’s first mover advantage in gaining access to available storage assets in the state of California and Brookfield’s knowledge in global clean energy markets. California is a world-leading location for the development of CCS projects, driven by the state’s Low Carbon Fuel Standard and Cap-and-Trade programs, together with the federal 45Q tax credit of $50 per ton of CO2 captured and permanently stored. CRC is currently progressing CO2 storage project permit applications and represents four out of the five Class VI well project applications active in California.
"We are pleased to partner with Brookfield to develop industry leading CCS projects that support California's energy transition," said Mac McFarland, CRC’s President and Chief Executive Officer. "The Brookfield partnership aligns our carbon management strategy with a strong investment partner, bringing significant operational and development expertise to reinforce our efforts. Brookfield's capital commitment also accelerates our carbon management opportunities. It also enables CRC to maintain capital discipline and financial flexibility to achieve our corporate objectives including achieving our Full-Scope Net Zero 2045 goal."
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“Transitioning our economy to net zero is a critical global challenge and that means rapidly scaling our available decarbonization technologies," said Connor Teskey, CEO of Brookfield Renewable. "Brookfield Renewable has been a leader in delivering clean energy for three decades and now we see significant potential in the rollout of carbon capture and sequestration technology. Partnering with CRC presents a great opportunity to continue the growth of our CCS business and expand the scope of decarbonization solutions we provide to our customers."
California Carbon Management Partnership Highlights
•CRC and Brookfield will jointly develop CCS projects in California through created JVs. The JVs will be owned 51% by CRC and 49% by BGTF
•The California Carbon Management Partnership with Brookfield is an important step in CRC’s Full-Scope Net Zero 2045 Goal and Carbon Management Strategy. It highlights the value of CRC's expansive CO2 pore space portfolio while demonstrating the Company’s commitment to capital discipline and retaining flexibility for strategic corporate objectives including shareholder returns and investing in the business
•Strengthens CRC’s competitive position in CCS deployment with Brookfield’s infrastructure investment experience, operating knowledge, and capital allocation. CRC and Brookfield are targeting the injection of 5 million metric tons of CO2 per annum over the first five years of the strategic partnership
•CRC is committing $2.5 million over the next three years to the Kern Community College District (Kern CCD) and California State University Bakersfield (CSUB) to promote innovation and implementation of energy transition in California
Second Quarter Operational and Financial Results
"During the second quarter of 2022, CRC continued to deliver strong operational results and shareholder returns," said Mac McFarland. "We expect to maintain our 2022 entry to exit net total production after taking into account asset divestitures. We are raising our full year EBITDAX1 and free cash flow guidance1 despite cost inflation and other macro pressures. With respect to our shareholder return strategy, CRC returned approximately 134% of its total generated free cash flow1 back to its shareholders in the form of dividends and share repurchases. The combination of our strong financial results coupled with ongoing capital investment and shareholder return strategies demonstrate our balanced commitment to our stakeholders."
McFarland continued, "Given prevailing market conditions, we are raising our adjusted EBITDAX1 and free cash flow1 guidance, and expect to continue our robust shareholder returns despite inflationary cost pressures. Further, the strategic partnership with Brookfield advances our carbon management energy transition efforts and provides increased capital flexibility with which we expect to pursue our overall corporate objectives and deliver on our financial goals and sustainability targets."
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Primary Highlights
•Raising full year 2022 adjusted EBITDAX1 and free cash flow1 guidance and reaffirming full year 2022 total production guidance of 91 to 94 thousand barrels of oil equivalent per day
•Investing approximately $13 million in natural gas assets located in the Sacramento Basin and the Buena Vista field to focus on quick and high impact workover opportunities
•In July 2022, CRC's fifth drilling rig began operations at the Wilmington Field
•Repurchased 2,255,445 common shares for $96 million during the second quarter of 2022; repurchased an aggregate 9,136,836 shares for $360 million since the inception of the Share Repurchase Program through July 31, 2022 for an average price of $39.34 per share
•Returned $193 million in total shareholder returns to investors throughout the first half of 2022, 34% more than the total free cash flow1 generated during the same period
•Declared a quarterly dividend of $0.17 per share of common stock, totaling $13 million payable on September 16, 2022 to shareholders of record on September 1, 2022, with subsequent quarterly dividends subject to final determination and Board approval
Financial
•Reported net income of $190 million, or $2.41 per fully diluted share. When adjusted for items analysts typically exclude from estimates including mark-to-market adjustments and gains on asset divestitures, the Company’s adjusted net income1 was $89 million, or $1.13 per fully diluted share
•Generated net cash provided by operating activities of $181 million, adjusted EBITDAX1 of $204 million and free cash flow1 of $83 million
•Ended the quarter with $324 million of cash on hand, an undrawn credit facility and $740 million of liquidity2
Operations
•Produced an average of 91,000 net barrels of oil equivalent per day (Boe/d), including 54,000 barrels of oil per day (Bo/d), with capital expenditures of $98 million during the quarter
•Operated three drilling rigs in the San Joaquin Basin and one drilling rig in the Los Angeles Basin; drilled 46 wells (42 online in 2Q22)
•Operated 33 maintenance rigs
Joint Venture Overview
The carbon management partnership will involve developing both infrastructure and storage assets required for CCS projects in California through newly created joint venture entities, Carbon TerraVault JV HoldCo, LLC ("HoldCo"), Carbon TerraVault JV Storage Company (“StorageCo”) and Carbon TerraVault JV Infrastructure Company, LLC (“InfraCo”).
StorageCo will build, install, operate, and maintain CO2 storage facilities. CRC has contributed
the storage rights in the 26R storage reservoir in the Elk Hills field to StorageCo. Brookfield has acquired an indirect 49% interest in StorageCo at an implied value of $10 per metric ton of permitted capacity, payable in three installments for a total consideration of $137 million. The first installment of $45.7 million was funded at close. The second and third installments are due upon completion of certain pre-agreed milestones related to the permitting process with the EPA and final investment decision. Future storage projects for Brookfield's initial commitment will be contributed on the same terms and milestones.
InfraCo will build, install, operate, maintain CO2 capture equipment and transportation assets, and provide funding as projects develop. StorageCo and InfraCo are wholly owned by HoldCo.
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2022 Production Guidance and Capital Program Update3
CRC's capital program is dynamic in response to oil market volatility and focused on maintaining oil production and strong liquidity and maximizing free cash flow. CRC is increasing its 2022 total capital program to a range of $380 to $410 million from $340 million to $385 million. CRC increased its 2022 capital program for inflation and these cost increases could also impact its capital program in 2023 and beyond. Additionally, in response to the continued strong commodity environment, CRC is adding to its workover program for natural gas assets located in the Sacramento Basin and the Buena Vista field. Finally, CRC has increased its capital program for its carbon management activities.
This level of expected spending is consistent with CRC's strategy of investing up to 50% of its operating cash flow back into CRC's oil and gas operations. Following the joint venture with Brookfield, CRC anticipates that a portion of the operating cash flow previously designated for advancing decarbonization and other emission reducing projects will now be available for other corporate purposes, such as shareholder returns and other strategic opportunities (see a summary of our Business Strategy in Part I, Item 1 & 2 – Business and Properties in CRC's 2021 Annual Report).
The delay in the Kern County EIR litigation (see Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Update in the Form 10-Q for the quarter ended June 30, 2022 for additional details on Kern County EIR) led to a change in CRC's drilling program which favors a higher natural gas to oil ratio. Therefore, CRC's 2022 oil production guidance is expected to be negatively impacted by approximately 1,000 Bo/d from this change as well as for 1,200 Boe/d for PSC. CRC's 2022 total production guidance remains consistent with previous expectations in the range of 91 to 94 MBoe/d.
With this capital program, and when adjusted for asset divestitures, production-sharing contracts (PSC) effects and the previously discussed Kern County EIR driven change in well mix, CRC expects to modestly grow oil production from entry to exit and is maintaining its total net production guidance. During the second half of 2022, CRC plans to run five drilling rigs in the Elk Hills, Buena Vista and Wilmington fields. In July 2022, CRC's fifth drilling rig began operations at the Wilmington Field.
In addition, CRC is raising its free cash flow1 and adjusted EBITDAX1 guidance by 10% and 2% at the midpoint, respectively, to $365 to $450 million and $895 to $960 million.
CRC is also raising its operating cost guidance to $725 to $755 million from $680 to $720 million due to inflation, change in well mix and higher natural gas and electricity prices.
Adjusted G&A guidance increased by $15 million to $185 to $200 million due primarily to wage and cost inflation as well as increased headcount as we develop our carbon management business.
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TOTAL CRC GUIDANCE3 | 2022E | CMB 2022E | E&P, Corp. & Other 2022E | ||||||||||||||
| Net Total Production (MBoe/d) | 94 - 91 | 94 - 91 | |||||||||||||||
| Net Oil Production (MBbl/d) | 58 - 53 | 58 - 53 | |||||||||||||||
| Operating Costs ($ millions) | $725 - $755 | $725 - $755 | |||||||||||||||
CMB Expenses4 ($ millions) | $20 - $30 | $20 - $30 | |||||||||||||||
Adjusted General and Administrative Expenses1 ($ millions) | $185 - $200 | $10 - $15 | $175 - $185 | ||||||||||||||
| Total Capital ($ millions) | $380 - $410 | $20 - $30 | $360 - $380 | ||||||||||||||
| Drilling & Completions | $260 - $265 | $260 - $265 | |||||||||||||||
Workovers | $40 - $45 | $40 - $45 | |||||||||||||||
Facilities | $55 - $60 | $55 - $60 | |||||||||||||||
Corporate & Other | $5 - $10 | $5 - $10 | |||||||||||||||
CMB | $20 - $30 | $20 - $30 | |||||||||||||||
Adjusted EBITDAX1 ($ millions) | $895 - $960 | ($30) - ($45) | $940 -- $990 | ||||||||||||||
Free Cash Flow1 ($ millions) | $365 - $450 | ($50) - ($75) | $440 - $500 | ||||||||||||||
Supporting Local Communities and Investing in the Energy Transition in California
Aligning with the strategic partnership, CRC will donate $2.5 million over the next three years to Kern Community College District (Kern CCD) and California State University Bakersfield (CSUB) to promote innovation and deployment of energy transition in California. This donation is expected to accelerate R&D efforts in decarbonization technologies in local academic research institutions located where CRC operates. CRC is dedicated to reducing emissions in California and is aligned with the state’s ambitious climate goals. As part of this pledge, CRC is also forming the CRC Carbon Management Institute at Kern CCD and is starting the CRC Energy Transition Lecture Series at CSUB.
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Supply Chain and Cost Inflation
Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity price environments which are cyclical in nature. Typically, suppliers will negotiate increases for drilling and completion, oilfield services, equipment and materials as prices for energy-related commodities and raw materials (such as steel, metals and chemicals) increase. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have created cost inflation during 2022 which may continue in future periods. CRC has taken proactive measures to limit the effects of the inflationary market by entering into contracts for materials and services with terms of one to three years. CRC has also taken steps to build its on-hand supply stock for items frequently used in its operations to address possible supply chain disruptions. Despite these efforts, CRC has experienced increased costs thus far in 2022 and CRC anticipates potential additional increases in the cost of goods and services and wages in its operations during the remainder of 2022. These increases have been factored into CRC's operating and capital costs guidance and could also negatively impact its results of operations and cash flows in 2023 and beyond.
Second Quarter 2022 E&P Operational Results
In November 2020, the SEC amended Regulation S-K to, among other things, provide companies with the option to discuss material changes to results of operations between the current and immediately preceding quarter. CRC has elected to discuss its results of operations on a sequential-quarter basis. CRC believes this approach provides more meaningful and useful information to measure its performance from the immediately preceding quarter. In accordance with this final rule, CRC is not required to include a comparison of the current quarter and the same prior-year quarter.
Total daily net production for the three months ended June 30, 2022, compared to the three months ended March 31, 2022 increased by approximately 3 MBoe/d, or 3%. This increase includes approximately 5 MBoe/d resulting from the return of production at one of CRC's cryogenic gas processing facilities, which had planned maintenance during the first quarter of 2022. These increases were partially offset by decreases resulting from natural decline, and the divestiture of CRC's remaining 50% working interest in certain zones in the Lost Hills field in February 2022. CRC's PSCs negatively impacted its net oil production in the three months ended June 30, 2022 by approximately 1 MBoe/d, compared to the three months ended March 31, 2022. The previously mentioned delays in the Kern County EIR litigation also negatively affected CRC's net oil production by 200 Bo/d for the three months ended June 30, 2022 due to the change in well mix.
During the second quarter of 2022, CRC operated an average of three drilling rigs in the San Joaquin Basin and one drilling rig in the Los Angeles Basin. During the quarter, CRC drilled 46 net wells and brought online 42 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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Second Quarter 2022 Financial Results
| 2nd Quarter | 1st Quarter | |||||||||||||
| ($ and shares in millions, except per share amounts) | 2022 | 2022 | ||||||||||||
| Statements of Operations: | ||||||||||||||
| Revenues | ||||||||||||||
| Total operating revenues | $ | 747 | $ | 153 | ||||||||||
| Operating Expenses | ||||||||||||||
| Total operating expenses | 473 | 396 | ||||||||||||
| Gain on asset divestitures | 4 | 54 | ||||||||||||
| Operating Income (Loss) | $ | 278 | $ | (189) | ||||||||||
| Net Income (Loss) Attributable to Common Stock | $ | 190 | $ | (175) | ||||||||||
| Net income (loss) per share - basic | $ | 2.48 | $ | (2.23) | ||||||||||
| Net income (loss) per share - diluted | $ | 2.41 | $ | (2.23) | ||||||||||
Adjusted net income1 | $ | 89 | $ | 91 | ||||||||||
Adjusted net income1 per share - diluted | $ | 1.13 | $ | 1.13 | ||||||||||
| Weighted-average common shares outstanding - basic | 76.7 | 78.5 | ||||||||||||
| Weighted-average common shares outstanding - diluted | 78.8 | 78.5 | ||||||||||||
Adjusted EBITDAX1 | $ | 204 | $ | 206 | ||||||||||
| 2nd Quarter | 1st Quarter | |||||||||||||
| ($ in millions) | 2022 | 2022 | ||||||||||||
| Cash Flow Data: | ||||||||||||||
| Net cash provided by operating activities | $ | 181 | $ | 160 | ||||||||||
| Net cash used in investing activities | $ | (76) | $ | (53) | ||||||||||
| Net cash used in financing activities | $ | (109) | $ | (84) | ||||||||||
Review of Second Quarter 2022 Financial Results
Realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, increased by $16.19 per barrel from $96.13 per barrel in the first quarter of 2022 to $112.32 per barrel in the second quarter of 2022. Realized oil prices were higher in the second quarter of 2022 compared to the first quarter of 2022 as the effects of the COVID-19 pandemic have subsided leaving crude oil production and product inventories at historically low levels. As demand has rebounded, producers have generally maintained capital discipline, OPEC+ members have failed to produce at stepped-up quotas, and the conflict between Russia and Ukraine has created a disconnect between buyers and sellers of Russian produced crude oil.
Realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, increased by $2.87 from $60.30 in the first quarter of 2022 to $63.17 in the second quarter of 2022. The increase is due to a higher commodity price environment in the second quarter of 2022 compared to the first quarter of 2022. See Attachment 4 for further information on prices.
Adjusted EBITDAX1 for the second quarter of 2022 was $204 million. See table below for the Company's net cash provided by operating activities, capital investments and free cash flow1 during the same periods.
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FREE CASH FLOW1 | ||||||||||||||||||||||||||||||||
| Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We supplemented our non-GAAP measure of free cash flow with free cash flow of our exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business. We define Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to our carbon management business. | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | |||||||||||||||||||||||||||||||
| ($ millions) | 2022 | 2022 | ||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 181 | $ | 160 | ||||||||||||||||||||||||||||
| Capital investments | (98) | (99) | ||||||||||||||||||||||||||||||
Free cash flow1 | $ | 83 | $ | 61 | ||||||||||||||||||||||||||||
E&P, corporate & other free cash flow1 | $ | 98 | $ | 64 | ||||||||||||||||||||||||||||
CMB free cash flow1 | $ | (15) | $ | (3) | ||||||||||||||||||||||||||||
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 purchases of natural gas used to generate electricity, purchased electricity and internal costs to generate electricity used in CRC's operations. Non-energy operating costs equal total operating costs less energy and gas processing costs. However, non-energy operating costs include the costs of purchasing natural gas from third parties that is used to generate steam for CRC's steamflood operations.
| OPERATING COSTS PER BOE | ||||||||||||||||||||||||||||||||
| The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs. | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | |||||||||||||||||||||||||||||||
| ($ per Boe) | 2022 | 2022 | ||||||||||||||||||||||||||||||
| Energy operating costs | $ | 6.88 | 6.68 | |||||||||||||||||||||||||||||
| Gas processing costs | 0.54 | 0.56 | ||||||||||||||||||||||||||||||
| Non-energy operating costs | 15.50 | 15.63 | ||||||||||||||||||||||||||||||
| Operating costs | $ | 22.92 | $ | 22.87 | ||||||||||||||||||||||||||||
| Excess costs attributable to PSCs | (2.58) | (2.30) | ||||||||||||||||||||||||||||||
Operating costs, excluding effects of PSCs (a) | $ | 20.34 | $ | 20.57 | ||||||||||||||||||||||||||||
| (a) Operating costs, excluding effects of PSCs is a non-GAAP measure. | ||||||||||||||||||||||||||||||||
Energy operating costs for the second quarter of 2022 were $57 million, or $6.88 per Boe, which was an increase of $4 million or 8% from $53 million, or $6.68 per Boe, for the first quarter of 2022. These increases were primarily a result of higher prices for purchased natural gas, which CRC used to generate electricity for its operations, and for purchased electricity. Energy operating costs were also higher on a per Boe basis as a result of lower production volumes between periods.
Non-energy operating costs for the second quarter of 2022 were $129 million, or 15.50 per Boe, which was an increase of $5 million or 4% from $124 million, or $15.63 per Boe, for the first quarter of 2022. This increase was primarily a result of higher compensation-related expenses and increased downhole maintenance activity.
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Balance Sheet and Liquidity Update
CRC's aggregate commitment under the Revolving Credit Facility was $552 million as of June 30, 2022. The borrowing base for the Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.2 billion on April 29, 2022.
As of June 30, 2022, CRC had liquidity of $740 million, which consisted of $324 million in cash and $416 million of available borrowing capacity under its Revolving Credit Facility.
Acquisitions and Divestitures
During the three months ended June 30, 2022, CRC recorded a gain of $4 million related to the sale of certain Ventura basin assets. The amount recognized in the three months ended June 30, 2022 of $4 million related to additional earn-out consideration on closings that occurred in the second half of 2021 and the first half of 2022. In addition, CRC received $2 million to secure the performance of abandonment obligations which CRC expects to reimburse to the buyer once the abandonment obligations are met. As a result, CRC recorded a liability of $2 million as of June 30, 2022, and CRC did not recognize gain on asset divestitures for this portion of the transaction. CRC expects to divest of its remaining assets in the Ventura basin during the second half of 2022, pending final approval from the State Lands Commission.
In June 2022, CRC sold its commercial office building located in Bakersfield, California for net proceeds of $13 million. In May 2022, CRC recorded a $2 million impairment charge to write down the carrying value of the building to its fair value.
Shareholder Returns Strategy
CRC continues to prioritize shareholder returns and dedicate a portion of its operating cash flow to shareholders. In light of this strategy, CRC's Board of Directors has authorized a Share Repurchase Program of $650 million, of which $290 million remains available for future repurchases.
During the second quarter of 2022, CRC repurchased 2.3 million shares of its common stock for $96 million. During the first half of 2022, CRC repurchased approximately 3.9 million shares of its common stock for $167 million. Since the inception of Share Repurchase Program through July 31, 2022, CRC has repurchased 9.1 million shares for $360 million at an average price of $39.34 per share, resulting in the repurchase of approximately 11% of the shares that CRC had at its emergence from bankruptcy.
On August 3, 2022, CRC's Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend is payable to shareholders of record on September 1, 2022, and will be paid on September 16, 2022.
Upcoming Investor Conference Participation
CRC's executives will be participating in the following in-person events in September 2022:
•Barclays CEO Energy Power Conference on September 6 - 8, 2022, in New York, NY
•Pickering Energy Partners TE&MFest Conference on September 15 -16, 2022, in Austin, TX
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•Credit Suisse 8th Annual Houston Oil & Gas Conference on September 20 - 21, 2022, in Houston, TX
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.
Advisors
Guggenheim Securities, LLC acted as financial advisor, and Sullivan & Cromwell LLP and Vinson & Elkins LLP acted as legal advisors for California Resources Corporation on the California Carbon Management Partnership with Brookfield Renewable deal.
Conference Call Details
To participate in the conference call scheduled for August 4, 2022, at 12:00 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 to https://dpregister.com/sreg/10167707/f307b93bd1. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.
1 See Attachment 2 for the non-GAAP financial measures of adjusted EBITDAX, operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted), free cash flow and free cash flow, after special items including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2022 estimates of the non-GAAP measures of adjusted EBITDAX and free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
2 Calculated as $324 million of cash plus $552 million of capacity on CRC's Revolving Credit Facility less $136 million in outstanding letters of credit
3 2022 guidance assumes a 2022 Brent price of $103.42 per barrel of oil, NGL realizations consistent with prior years and a NYMEX gas price of $5.62 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
4 CMB Expenses include start-up expenditures.
About California Resources Corporation
California Resources Corporation (CRC) is an independent oil and natural gas company committed to energy transition in the sector. CRC has some of the lowest carbon intensity production in the US and we are 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, HoldCo or any of their respective subsidiaries and affiliates.
About Brookfield Renewable
Brookfield Renewable operates one of the world’s largest publicly traded, pure-play renewable power platforms. Its portfolio consists of hydroelectric, wind, solar and storage facilities in North America, South America, Europe and Asia, and totals approximately 21,000MW of installed capacity and an approximately 69,000MW development pipeline. Investors can access its portfolio either through Brookfield Renewable Partners L.P. (NYSE: BEP; TSX: BEP.UN), or Brookfield Renewable Corporation (NYSE, TSX: BEPC), a Canadian corporation. Brookfield Renewable is the flagship listed renewable power company of Brookfield Asset Management, a leading global alternative asset manager with approximately $725 billion of assets under management.
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The Brookfield Global Transition Fund, co-led by Mark Carney, Brookfield Vice Chair and Head of Transition Investing, and Connor Teskey, CEO of Brookfield Renewable, is Brookfield’s inaugural impact fund focusing on investments that accelerate the global transition to a net-zero carbon economy, while delivering strong risk-adjusted returns to investors.
The Fund targets investment opportunities relating to reducing greenhouse gas emissions and energy consumption, as well as increasing low-carbon energy capacity and supporting sustainable solutions. Consistent with its dual objectives of earning strong risk-adjusted returns and generating a measurable positive environmental change, the Fund will report to investors on both its financial and environmental impact performance.
Forward-Looking Statements
This document contains statements that we believe 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 we believe the expectations and forecasts reflected in CRC's 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 our actual results to be materially different than those expressed in CRC's forward-looking statements include:
•fluctuations in commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices;
•equipment, service or labor price inflation or unavailability;
•legislative or regulatory changes, including those related to (i) drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) managing energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) protection of health, safety and the environment, (iv) tax credits or other incentives, or (v) transportation, marketing and sale of our products;
•availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities and carbon management projects;
•changes in business strategy and CRC's capital plan;
•lower-than-expected production, reserves or resources from development projects or acquisitions, or higher-than-expected decline rates;
•incorrect estimates of reserves and related future cash flows and the inability to replace reserves;
•the recoverability of resources and unexpected geologic conditions;
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•CRC’s ability to utilize storage capacity of the 26R storage reservoir consistent with the Joint Venture and Investment Agreement through either storage only contracts or as part of an integrated project;
•CRC’s ability to identify and develop projects that are acceptable to the JV;
•CRC’s ability to successfully execute on the construction and other aspects of the infrastructure projects and enter into third party contracts on contemplated terms;
•CRC’s ability to realize all benefits contemplated by the strategic partnership and business strategies and initiatives related to energy transition, including CCS projects and other renewable energy efforts;
•CRC's ability to finance and implement its CCS projects, including the development of projects contemplated as part of the strategic partnership with Brookfield;
•global geopolitical, socio-demographic and economic trends and technological innovations;
•changes in our dividend policy and our ability to declare future dividends;
•production-sharing contracts' effects on production and operating costs;
•limitations on CRC's financial flexibility due to existing and future debt;
•insufficient cash flow to fund planned investments, interest payments on our debt, stock repurchases or changes to CRC's capital plan;
•insufficient capital or liquidity unavailability of capital markets or inability to attract potential investors;
•limitations on transportation or storage capacity and the need to shut-in wells;
•inability to enter into desirable transactions, including acquisitions, asset sales and joint ventures;
•joint ventures and acquisitions and CRC's ability to achieve expected synergies;
•CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
•CRC's ability to successfully gather and verify data regarding emissions, its environmental impacts and other initiatives;
•the compliance of various third parties with CRC's policies and procedures and legal requirements as well as contracts CRC enters into in connection with its climate-related initiatives;
•the effect of CRC's stock price on costs associated with incentive compensation;
•changes in the intensity of competition in the oil and gas industry;
•effects of hedging transactions;
•climate-related conditions and weather events;
•disruptions due to accidents, mechanical failures, power outages, transportation or storage constraints, natural disasters, labor difficulties, cyber-attacks or other catastrophic events;
•pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19; and
•other factors discussed in Part I, Item 1A – Risk Factors in CRC's Annual Report on Form 10-K and its other SEC filings available at www.crc.com.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and CRC undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.
Contacts:
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| Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com | Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com | ||||
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| Attachment 1 | ||||||||||||||||||||||||||||||||
| SUMMARY OF RESULTS | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||
| ($ and shares in millions, except per share amounts) | 2022 | 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||||||
| Statements of Operations: | ||||||||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 718 | $ | 628 | $ | 478 | $ | 1,346 | $ | 910 | ||||||||||||||||||||||
| Net loss from commodity derivatives | (100) | (562) | (265) | (662) | (478) | |||||||||||||||||||||||||||
| Sales of purchased natural gas | 75 | 32 | 48 | 107 | 146 | |||||||||||||||||||||||||||
| Electricity sales | 49 | 34 | 33 | 83 | 66 | |||||||||||||||||||||||||||
| Other revenue | 5 | 21 | 10 | 26 | 23 | |||||||||||||||||||||||||||
| Total operating revenues | 747 | 153 | 304 | 900 | 667 | |||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||
| Operating costs | 190 | 182 | 169 | 372 | 333 | |||||||||||||||||||||||||||
| General and administrative expenses | 56 | 48 | 48 | 104 | 96 | |||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 50 | 49 | 54 | 99 | 106 | |||||||||||||||||||||||||||
| Asset impairments | 2 | — | — | 2 | 3 | |||||||||||||||||||||||||||
| Taxes other than on income | 42 | 34 | 37 | 76 | 77 | |||||||||||||||||||||||||||
| Exploration expense | 1 | 1 | 2 | 2 | 4 | |||||||||||||||||||||||||||
| Purchased natural gas expense | 67 | 21 | 30 | 88 | 91 | |||||||||||||||||||||||||||
| Electricity generation expenses | 33 | 24 | 17 | 57 | 41 | |||||||||||||||||||||||||||
| Transportation costs | 12 | 12 | 14 | 24 | 26 | |||||||||||||||||||||||||||
| Accretion expense | 11 | 11 | 13 | 22 | 26 | |||||||||||||||||||||||||||
| Other operating expenses, net | 9 | 14 | 10 | 23 | 27 | |||||||||||||||||||||||||||
| Total operating expenses | 473 | 396 | 394 | 869 | 830 | |||||||||||||||||||||||||||
| Net gain on asset divestitures | 4 | 54 | — | 58 | — | |||||||||||||||||||||||||||
| Operating Income (Loss) | 278 | (189) | (90) | 89 | (163) | |||||||||||||||||||||||||||
| Non-Operating (Expenses) Income | ||||||||||||||||||||||||||||||||
| Reorganization items, net | — | — | (2) | — | (4) | |||||||||||||||||||||||||||
| Interest and debt expense, net | (13) | (13) | (13) | (26) | (26) | |||||||||||||||||||||||||||
| Net loss on early extinguishment of debt | — | — | — | — | (2) | |||||||||||||||||||||||||||
| Other non-operating expenses, net | 1 | 1 | (2) | 2 | (1) | |||||||||||||||||||||||||||
| Net Income (Loss) Before Income Taxes | 266 | (201) | (107) | 65 | (196) | |||||||||||||||||||||||||||
| Income tax (provision) benefit | (76) | 26 | — | (50) | — | |||||||||||||||||||||||||||
| Net income (loss) | 190 | (175) | (107) | 15 | (196) | |||||||||||||||||||||||||||
| Net income attributable to noncontrolling interests | — | — | (4) | — | (9) | |||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Common Stock | $ | 190 | $ | (175) | $ | (111) | $ | 15 | $ | (205) | ||||||||||||||||||||||
| Net income (loss) attributable to common stock per share - basic | $ | 2.48 | $ | (2.23) | $ | (1.34) | $ | 0.19 | $ | (2.46) | ||||||||||||||||||||||
| Net income (loss) attributable to common stock per share - diluted | $ | 2.41 | $ | (2.23) | $ | (1.34) | $ | 0.19 | $ | (2.46) | ||||||||||||||||||||||
| Adjusted net income | $ | 89 | $ | 91 | $ | 78 | $ | 180 | $ | 180 | ||||||||||||||||||||||
| Adjusted net income per share - basic | $ | 1.16 | $ | 1.16 | $ | 0.94 | $ | 2.32 | $ | 2.16 | ||||||||||||||||||||||
| Adjusted net income per share - diluted | $ | 1.13 | $ | 1.13 | $ | 0.94 | $ | 2.26 | $ | 2.15 | ||||||||||||||||||||||
| Weighted-average common shares outstanding - basic | 76.7 | 78.5 | 83.1 | 77.6 | 83.2 | |||||||||||||||||||||||||||
| Weighted-average common shares outstanding - diluted | 78.8 | 78.5 | 83.1 | 79.6 | 83.2 | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 204 | $ | 206 | $ | 169 | $ | 410 | $ | 358 | ||||||||||||||||||||||
| Effective tax rate | 29 | % | 13 | % | 0% | 78 | % | 0% | ||||||||||||||||||||||||
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| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ in millions) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Cash Flow Data: | |||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 181 | $ | 160 | $ | 127 | $ | 341 | $ | 274 | |||||||||||||||||||
| Net cash used in investing activities | $ | (76) | $ | (53) | $ | (43) | $ | (129) | $ | (63) | |||||||||||||||||||
| Net cash used by financing activities | $ | (109) | $ | (84) | $ | (63) | $ | (193) | $ | (88) | |||||||||||||||||||
| June 30. | December 31, | ||||||||||
| ($ and shares in millions) | 2022 | 2021 | |||||||||
| Selected Balance Sheet Data: | |||||||||||
| Total current assets | $ | 851 | $ | 753 | |||||||
| Property, plant and equipment, net | $ | 2,675 | $ | 2,599 | |||||||
| Deferred tax asset | $ | 367 | $ | 396 | |||||||
| Total current liabilities | $ | 1,208 | $ | 854 | |||||||
| Long-term debt, net | $ | 591 | $ | 589 | |||||||
| Noncurrent asset retirement obligations | $ | 409 | $ | 438 | |||||||
| Stockholders' Equity | $ | 1,517 | $ | 1,688 | |||||||
| Outstanding shares | 75.4 | 79.3 | |||||||||
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| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Non-cash derivative gain (loss) | $ | 141 | $ | (381) | $ | (183) | $ | (240) | $ | (357) | |||||||||||||||||||
| Net payments on settled commodity derivatives | (241) | (181) | (82) | (422) | (121) | ||||||||||||||||||||||||
| Net loss from commodity derivatives | $ | (100) | $ | (562) | $ | (265) | $ | (662) | $ | (478) | |||||||||||||||||||
| 1st Quarter | 1st Quarter | 4th Quarter | 4th Quarter | 4th Quarter | |||||||||||||||||||||||||||||||||||||
| CAPITAL INVESTMENTS | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Facilities | $ | 15 | $ | 17 | $ | 11 | $ | 32 | $ | 18 | |||||||||||||||||||
| Drilling | 62 | 59 | 28 | 121 | 41 | ||||||||||||||||||||||||
| Workovers | 9 | 6 | 10 | 15 | 17 | ||||||||||||||||||||||||
| Total E&P capital | 86 | 82 | 49 | 168 | 76 | ||||||||||||||||||||||||
| CMB | 10 | 1 | — | 11 | — | ||||||||||||||||||||||||
| Other | 2 | 16 | 1 | 18 | 1 | ||||||||||||||||||||||||
| Total capital program | $ | 98 | $ | 99 | $ | 50 | $ | 197 | $ | 77 | |||||||||||||||||||
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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, adjusted EBITDAX margin, discretionary cash flow, free cash flow and operating costs per BOE, among others. These measures are also widely used by the industry, the investment community and our lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the effect of acquisition and development costs of our assets. Management believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of the non-GAAP measures reported in this press release, including reconciliations to their most directly comparable GAAP measure where applicable. | ||||||||||||||||||||||||||
| ADJUSTED NET INCOME (LOSS) | |||||||||||||||||||||||||||||
| Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. We define adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing our financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measure of adjusted net income (loss) and adjusted net income (loss) per share. | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions, except per share amounts) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Net income (loss) | $ | 190 | $ | (175) | $ | (107) | $ | 15 | $ | (196) | |||||||||||||||||||
| Net income attributable to noncontrolling interests | — | — | (4) | — | (9) | ||||||||||||||||||||||||
| Net income (loss) attributable to common stock | 190 | (175) | (111) | 15 | (205) | ||||||||||||||||||||||||
| Unusual, infrequent and other items: | |||||||||||||||||||||||||||||
| Non-cash (income) loss from commodity derivatives | (141) | 381 | 183 | 240 | 357 | ||||||||||||||||||||||||
| Asset impairments | 2 | — | — | 2 | 3 | ||||||||||||||||||||||||
| Reorganization items, net | — | — | 2 | — | 4 | ||||||||||||||||||||||||
| Severance and termination costs | — | — | 1 | — | 15 | ||||||||||||||||||||||||
| Net loss on early extinguishment of debt | — | — | — | — | 2 | ||||||||||||||||||||||||
| Net gain on asset divestitures | (4) | (54) | — | (58) | (2) | ||||||||||||||||||||||||
| Rig termination expenses | — | — | 1 | — | 2 | ||||||||||||||||||||||||
| Other, net | 2 | 1 | 2 | 3 | 4 | ||||||||||||||||||||||||
| Total unusual, infrequent and other items | (141) | 328 | 189 | 187 | 385 | ||||||||||||||||||||||||
| Income tax benefit (provision) of adjustments at effective tax rate | 40 | (93) | — | (53) | — | ||||||||||||||||||||||||
| Valuation allowance | — | 31 | — | 31 | — | ||||||||||||||||||||||||
| Adjusted net income attributable to common stock | $ | 89 | $ | 91 | $ | 78 | $ | 180 | $ | 180 | |||||||||||||||||||
| Net income (loss) attributable to common stock per share - basic | $ | 2.48 | $ | (2.23) | $ | (1.34) | $ | 0.19 | $ | (2.46) | |||||||||||||||||||
| Net income (loss) attributable to common stock per share - diluted | $ | 2.41 | $ | (2.23) | $ | (1.34) | $ | 0.19 | $ | (2.46) | |||||||||||||||||||
| Adjusted net income per share - basic | $ | 1.16 | $ | 1.16 | $ | 0.94 | $ | 2.32 | $ | 2.16 | |||||||||||||||||||
| Adjusted net income per share - diluted | $ | 1.13 | $ | 1.13 | $ | 0.94 | $ | 2.26 | $ | 2.15 | |||||||||||||||||||
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| FREE CASH FLOW | |||||||||||||||||||||||||||||
| Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We supplemented our non-GAAP measure of free cash flow with free cash flow of our exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business. We define Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to our carbon management business. We have excluded one-time costs for bankruptcy related fees during 2021 and 2020 as a supplemental measure of our free cash flow. | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 181 | $ | 160 | $ | 127 | $ | 341 | $ | 274 | |||||||||||||||||||
| Capital investments | (98) | (99) | (50) | (197) | (77) | ||||||||||||||||||||||||
| Free cash flow | 83 | 61 | 77 | 144 | 197 | ||||||||||||||||||||||||
| One-time bankruptcy related fees | — | — | 2 | — | 4 | ||||||||||||||||||||||||
| Free cash flow, after special items | $ | 83 | $ | 61 | $ | 79 | $ | 144 | $ | 201 | |||||||||||||||||||
| E&P, Corporate and Other Free Cash Flow | $ | 98 | $ | 64 | $ | 79 | $ | 162 | $ | 201 | |||||||||||||||||||
| CMB Free Cash Flow | $ | (15) | $ | (3) | $ | — | $ | (18) | $ | — | |||||||||||||||||||
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| ADJUSTED EBITDAX | ||||||||||||||||||||||||||||||||
We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as depreciation, depletion and amortization of our assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of our financial covenants under our Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. 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. We have supplemented our non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for our exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business.. We define adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to our carbon management business (CMB). | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||
| ($ millions, except per BOE amounts) | 2022 | 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||||||
| Net income (loss) | $ | 190 | $ | (175) | $ | (107) | $ | 15 | $ | (196) | ||||||||||||||||||||||
| Interest and debt expense, net | 13 | 13 | 13 | 26 | 26 | |||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 50 | 49 | 54 | 99 | 106 | |||||||||||||||||||||||||||
| Income tax provision (benefit) | 76 | (26) | — | 50 | — | |||||||||||||||||||||||||||
| Exploration expense | 1 | 1 | 2 | 2 | 4 | |||||||||||||||||||||||||||
Unusual, infrequent and other items (a) | (141) | 328 | 189 | 187 | 385 | |||||||||||||||||||||||||||
| Non-cash items | ||||||||||||||||||||||||||||||||
| Accretion expense | 11 | 11 | 13 | 22 | 26 | |||||||||||||||||||||||||||
| Stock-based compensation | 4 | 4 | 4 | 8 | 6 | |||||||||||||||||||||||||||
| Post-retirement medical and pension | — | 1 | 1 | 1 | 1 | |||||||||||||||||||||||||||
| Other non-cash items | — | — | — | — | — | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 204 | $ | 206 | $ | 169 | $ | 410 | $ | 358 | ||||||||||||||||||||||
| Net cash used by operating activities | $ | 181 | $ | 160 | $ | 127 | $ | 341 | $ | 274 | ||||||||||||||||||||||
| Cash interest | 2 | 23 | 2 | 25 | 5 | |||||||||||||||||||||||||||
| Cash income taxes | 20 | — | — | 20 | — | |||||||||||||||||||||||||||
| Exploration expenditures | 1 | 1 | 2 | 2 | 4 | |||||||||||||||||||||||||||
| Working capital changes | — | 22 | 38 | 22 | 75 | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 204 | $ | 206 | $ | 169 | $ | 410 | $ | 358 | ||||||||||||||||||||||
| E&P, Corporate & Other Adjusted EBITDAX | $ | 209 | $ | 208 | $ | 169 | $ | 417 | $ | 358 | ||||||||||||||||||||||
| CMB Adjusted EBITDAX | $ | (5) | $ | (2) | $ | — | $ | (7) | $ | — | ||||||||||||||||||||||
| Adjusted EBITDAX per Boe | $ | 24.61 | $ | 25.89 | $ | 18.48 | $ | 25.24 | $ | 19.78 | ||||||||||||||||||||||
| (a) See Adjusted Net Income (Loss) reconciliation. | ||||||||||||||||||||||||||||||||
Page 19
| 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. We supplemented our non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of our exploration and production and corporate items (Adjusted General & Administrative Expenses for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results or our core oil and gas business. We define Adjusted General & Administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to our carbon management business | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| General and administrative expenses | $ | 56 | $ | 48 | $ | 48 | $ | 104 | $ | 96 | |||||||||||||||||||
| Stock-based compensation | (4) | (4) | (4) | (8) | (6) | ||||||||||||||||||||||||
| ERP implementation costs | (1) | — | — | (1) | — | ||||||||||||||||||||||||
| Adjusted G&A expenses | $ | 51 | $ | 44 | $ | — | $ | 44 | $ | 95 | $ | 90 | |||||||||||||||||
| E&P, Corporate and Other Adjusted G&A expenses | $ | 47 | 43 | $ | 43 | $ | 44 | $ | 90 | $ | 90 | ||||||||||||||||||
| CMB Adjusted G&A expenses | $ | 4 | $ | 1 | $ | — | $ | 5 | $ | — | |||||||||||||||||||
| OPERATING COSTS PER BOE | |||||||||||||||||||||||||||||
| The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.The following table presents operating costs after adjusting for the excess costs attributable to PSCs. | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ per BOE) | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
Energy operating costs (1) | $ | 6.88 | $ | 6.68 | $ | 4.70 | $ | 6.78 | $ | 4.70 | |||||||||||||||||||
| Gas processing costs | 0.54 | 0.56 | 0.66 | 0.55 | 0.60 | ||||||||||||||||||||||||
Non-energy operating costs (2) | 15.50 | 15.63 | 13.12 | 15.57 | 13.10 | ||||||||||||||||||||||||
| Operating costs | $ | 22.92 | $ | 22.87 | $ | 18.48 | $ | 22.90 | $ | 18.40 | |||||||||||||||||||
| Costs attributable to PSCs | |||||||||||||||||||||||||||||
| Excess energy operating costs attributable to PSCs | $ | (1.03) | $ | (0.90) | $ | (0.63) | $ | (0.96) | $ | (0.60) | |||||||||||||||||||
| Excess non-energy operating costs attributable to PSCs | (1.55) | (1.40) | (1.10) | (1.49) | (1.06) | ||||||||||||||||||||||||
| Excess costs attributable to PSCs | $ | (2.58) | $ | (2.30) | $ | (1.73) | $ | (2.45) | $ | (1.66) | |||||||||||||||||||
Energy operating costs, excluding effect of PSCs (1) | $ | 5.85 | $ | 5.78 | $ | 4.07 | $ | 5.82 | $ | 4.10 | |||||||||||||||||||
| Gas processing costs, excluding effect of PSCs | 0.54 | 0.56 | 0.66 | 0.55 | 0.60 | ||||||||||||||||||||||||
Non-energy operating costs, excluding effect of PSCs (2) | 13.95 | 14.23 | 12.02 | 14.08 | 12.04 | ||||||||||||||||||||||||
| Operating costs, excluding effects of PSCs | $ | 20.34 | $ | 20.57 | $ | 16.75 | $ | 20.45 | $ | 16.74 | |||||||||||||||||||
| (1) Energy operating costs consist of purchases of natural gas to generate electricity, purchased electricity and internal costs to produce electricity used in our operations. | |||||||||||||||||||||||||||||
| (2) Non-energy operating costs equal total operating costs less energy and gas processing costs. However, non-energy operating costs include the costs of purchasing natural gas used to generate steam for our steamfloods. | |||||||||||||||||||||||||||||
Page 20
| Attachment 3 | |||||||||||||||||||||||||||||
| PRODUCTION STATISTICS | |||||||||||||||||||||||||||||
| Net | 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||
| Oil, NGLs and Natural Gas Production Per Day | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 38 | 38 | 39 | 38 | 38 | ||||||||||||||||||||||||
| Los Angeles Basin | 16 | 18 | 19 | 17 | 20 | ||||||||||||||||||||||||
| Ventura Basin | — | — | 3 | — | 2 | ||||||||||||||||||||||||
| Total | 54 | 56 | 61 | 55 | 60 | ||||||||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 12 | 9 | 13 | 11 | 12 | ||||||||||||||||||||||||
| Ventura Basin | — | — | — | — | 1 | ||||||||||||||||||||||||
| Total | 12 | 9 | 13 | 11 | 13 | ||||||||||||||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 132 | 121 | 135 | 127 | 135 | ||||||||||||||||||||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||
| Ventura Basin | — | — | 5 | — | 5 | ||||||||||||||||||||||||
| Sacramento Basin | 18 | 19 | 20 | 18 | 20 | ||||||||||||||||||||||||
| Total | 151 | 141 | 161 | 146 | 161 | ||||||||||||||||||||||||
| Total Production (MBoe/d) | 91 | 88 | 101 | 90 | 100 | ||||||||||||||||||||||||
| Gross Operated and Net Non-Operated | 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||
| Oil, NGLs and Natural Gas Production Per Day | 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 42 | 43 | 45 | 42 | 45 | ||||||||||||||||||||||||
| Los Angeles Basin | 25 | 26 | 27 | 26 | 27 | ||||||||||||||||||||||||
| Ventura Basin | — | — | 3 | — | 3 | ||||||||||||||||||||||||
| Total | 67 | 69 | 75 | 68 | 75 | ||||||||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 13 | 9 | 14 | 11 | 12 | ||||||||||||||||||||||||
| Ventura Basin | — | — | — | — | 1 | ||||||||||||||||||||||||
| Total | 13 | 9 | 14 | 11 | 13 | ||||||||||||||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 141 | 129 | 144 | 135 | 144 | ||||||||||||||||||||||||
| Los Angeles Basin | 7 | 8 | 8 | 7 | 8 | ||||||||||||||||||||||||
| Ventura Basin | — | — | 5 | — | 5 | ||||||||||||||||||||||||
| Sacramento Basin | 22 | 23 | 24 | 23 | 24 | ||||||||||||||||||||||||
| Total | 170 | 160 | 181 | 165 | 181 | ||||||||||||||||||||||||
| Total Production (MBoe/d) | 108 | 105 | 119 | 106 | 118 | ||||||||||||||||||||||||
| 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. | |||||||||||||||||||||||||||||
Page 21
| Attachment 4 | ||||||||||||||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||
| 2022 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||||||
| Oil ($ per Bbl) | ||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 63.17 | $ | 60.30 | $ | 54.10 | $ | 61.71 | $ | 53.91 | ||||||||||||||||||||||
| Realized price without derivative settlements | $ | 112.32 | $ | 96.13 | $ | 68.94 | $ | 104.07 | $ | 64.89 | ||||||||||||||||||||||
| NGLs ($/Bbl) | $ | 68.29 | $ | 78.63 | $ | 44.90 | $ | 72.57 | $ | 46.75 | ||||||||||||||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 6.72 | $ | 6.28 | $ | 3.03 | $ | 6.51 | $ | 3.14 | ||||||||||||||||||||||
| Realized price without derivative settlements | $ | 6.85 | $ | 6.28 | $ | 3.04 | $ | 6.58 | $ | 3.17 | ||||||||||||||||||||||
| Index Prices | ||||||||||||||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 111.79 | $ | 97.38 | $ | 69.02 | $ | 104.59 | $ | 65.06 | ||||||||||||||||||||||
| WTI oil ($/Bbl) | $ | 108.41 | $ | 94.29 | $ | 66.07 | $ | 101.35 | $ | 61.96 | ||||||||||||||||||||||
| NYMEX Henry Hub average daily price ($/MMBtu) | $ | 6.62 | $ | 4.19 | $ | 2.76 | $ | 5.40 | $ | 2.74 | ||||||||||||||||||||||
| NYMEX Henry Hub average monthly settled price ($/MMBtu) | $ | 7.17 | $ | 4.95 | $ | 2.83 | $ | 6.06 | $ | 2.76 | ||||||||||||||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 57 | % | 62 | % | 78 | % | 59 | % | 83 | % | ||||||||||||||||||||||
| Oil without derivative settlements as a percentage of Brent | 100 | % | 99 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||
| Oil with derivative settlements as a percentage of WTI | 58 | % | 64 | % | 82 | % | 61 | % | 87 | % | ||||||||||||||||||||||
| Oil without derivative settlements as a percentage of WTI | 104 | % | 102 | % | 104 | % | 103 | % | 105 | % | ||||||||||||||||||||||
| NGLs as a percentage of Brent | 61 | % | 81 | % | 65 | % | 69 | % | 72 | % | ||||||||||||||||||||||
| NGLs as a percentage of WTI | 63 | % | 83 | % | 68 | % | 72 | % | 75 | % | ||||||||||||||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX average daily price | 102 | % | 150 | % | 110 | % | 121 | % | 115 | % | ||||||||||||||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX average monthly settled price | 94 | % | 127 | % | 107 | % | 107 | % | 114 | % | ||||||||||||||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX average daily price | 103 | % | 150 | % | 110 | % | 122 | % | 116 | % | ||||||||||||||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX average monthly settled price | 96 | % | 127 | % | 107 | % | 109 | % | 115 | % | ||||||||||||||||||||||
Page 22
| Attachment 5 | |||||||||||||||||||||||||||||
| SECOND QUARTER 2022 DRILLING ACTIVITY | |||||||||||||||||||||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||||||||||||||||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||||||||||||||||||||||
| Development Wells | |||||||||||||||||||||||||||||
| Primary | 5 | — | — | — | 5 | ||||||||||||||||||||||||
| Waterflood | 6 | 7 | — | — | 13 | ||||||||||||||||||||||||
| Steamflood | 28 | — | — | — | 28 | ||||||||||||||||||||||||
Total (1) | 39 | 7 | — | — | 46 | ||||||||||||||||||||||||
| SIX MONTH 2022 DRILLING ACTIVITY | |||||||||||||||||||||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||||||||||||||||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||||||||||||||||||||||
| Development Wells | |||||||||||||||||||||||||||||
| Primary | 8 | — | — | — | 8 | ||||||||||||||||||||||||
| Waterflood | 27 | 14 | — | — | 41 | ||||||||||||||||||||||||
| Steamflood | 39 | — | — | — | 39 | ||||||||||||||||||||||||
Total (1) | 74 | 14 | — | — | 88 | ||||||||||||||||||||||||
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | |||||||||||||||||||||||||||||
Page 23
| Attachment 6 | ||||||||||||||||||||||||||||||||||||||
| OIL HEDGES AS OF JUNE 30, 2022 | ||||||||||||||||||||||||||||||||||||||
| Q3 2022 | Q4 2022 | Q1 2023 | Q2 2023 | 2H 2023 | 2024 | |||||||||||||||||||||||||||||||||
| Sold Calls | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 34,380 | 25,167 | 18,322 | 17,837 | 11,555 | — | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $60.76 | $57.82 | $57.28 | $60.00 | $57.06 | — | ||||||||||||||||||||||||||||||||
| Swaps | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 10,476 | 17,263 | 14,620 | 14,475 | 19,395 | 1,492 | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $53.97 | $58.79 | $67.36 | $66.36 | $68.05 | $79.06 | ||||||||||||||||||||||||||||||||
Net Purchased Puts 1 | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 34,380 | 25,167 | 18,322 | 17,837 | 11,555 | 1,724 | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $65.02 | $64.47 | $76.25 | $76.25 | $76.25 | $75.00 | ||||||||||||||||||||||||||||||||
| Sold Puts | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 4,000 | 1,348 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $32.00 | $32.00 | — | — | — | — | ||||||||||||||||||||||||||||||||
1 Purchased and sold puts with the same strike price have been netted together. | ||||||||||||||||||||||||||||||||||||||
Page 24
| Attachment 7 | |||||||||||||||||
| 2022 Estimated | |||||||||||||||||
TOTAL CRC GUIDANCE1 | Consolidated | CMB | E&P, Corporate & Other | ||||||||||||||
| Net Total Production (MBoe/d) | 91 - 94 | 91 - 94 | |||||||||||||||
| Net Oil Production (MBbl/d) | 53 - 58 | 53 - 58 | |||||||||||||||
| Operating Costs ($ millions) | $725 - $755 | $725 - $755 | |||||||||||||||
CMB Expenses2 ($ millions) | $20 - $30 | $20 - $30 | |||||||||||||||
| Adjusted General and Administrative Expenses ($ millions) | $185 - $200 | $10 - $15 | $175 - $185 | ||||||||||||||
| Capital ($ millions) | $380 - $410 | $20 - $30 | $360 - $380 | ||||||||||||||
| Adjusted EBITDAX ($ millions) | $895 - $960 | ($30) - ($45) | $940 - $990 | ||||||||||||||
| Free Cash Flow ($ millions) | $365 - $450 | ($50) - ($75) | $440 - $500 | ||||||||||||||
See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX and consolidated free cash flow with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) and free cash flow from our exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes are useful measures for investors to understand the results of its core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB). CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less results attributable to CMB.
| 2022 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| Net cash provided (used) by operating activities | $ | 775 | $ | 830 | $ | (45) | $ | (30) | $ | 820 | $ | 860 | |||||||||||||||||||||||
| Capital investments | (410) | (380) | (30) | (20) | (380) | (360) | |||||||||||||||||||||||||||||
| Estimated free cash flow | $ | 365 | $ | 450 | $ | (75) | $ | (50) | $ | 440 | $ | 500 | |||||||||||||||||||||||
Page 25
| 2022 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| Net income | $ | 495 | $ | 515 | $ | (45) | $ | (30) | $ | 540 | $ | 545 | |||||||||||||||||||||||
| Interest and debt expense, net | 50 | 56 | 50 | 56 | |||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 200 | 210 | 200 | 210 | |||||||||||||||||||||||||||||||
| Exploration expense | 7 | 10 | 7 | 10 | |||||||||||||||||||||||||||||||
| Income taxes | 232 | 256 | 232 | 256 | |||||||||||||||||||||||||||||||
| Unusual, infrequent and other items | |||||||||||||||||||||||||||||||||||
| Non-cash derivative gain | (90) | (99) | (90) | (99) | |||||||||||||||||||||||||||||||
| Gain on asset divestitures | (58) | (58) | (58) | (58) | |||||||||||||||||||||||||||||||
| Other | 2 | 4 | 2 | 4 | |||||||||||||||||||||||||||||||
| Other non-cash items | |||||||||||||||||||||||||||||||||||
| Accretion expense | 40 | 46 | 40 | 46 | |||||||||||||||||||||||||||||||
| Stock-based compensation | 15 | 18 | 15 | 18 | |||||||||||||||||||||||||||||||
| Post-retirement medical and pension | 2 | 2 | 2 | 2 | |||||||||||||||||||||||||||||||
| Estimated adjusted EBITDAX | $ | 895 | $ | 960 | $ | (45) | $ | (30) | $ | 940 | $ | 990 | |||||||||||||||||||||||
| Net cash provided (used) by operating activities | $ | 775 | $ | 830 | $ | (45) | $ | (30) | $ | 820 | $ | 860 | |||||||||||||||||||||||
| Cash interest | 44 | 48 | 44 | 48 | |||||||||||||||||||||||||||||||
| Cash income taxes | 32 | 38 | 32 | 38 | |||||||||||||||||||||||||||||||
| Exploration expenditures | 7 | 7 | 7 | 7 | |||||||||||||||||||||||||||||||
| Working capital changes | 37 | 37 | 37 | 37 | |||||||||||||||||||||||||||||||
| Estimated adjusted EBITDAX | $ | 895 | $ | 960 | $ | (45) | $ | (30) | $ | 940 | $ | 990 | |||||||||||||||||||||||
| 2022 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| General and administrative expenses | $ | 215 | $ | 225 | $ | 10 | $ | 15 | $ | 205 | $ | 210 | |||||||||||||||||||||||
| Equity-settled stock-based compensation | (23) | (18) | (23) | (18) | |||||||||||||||||||||||||||||||
| ERP implementation Costs | (7) | (7) | (7) | (7) | |||||||||||||||||||||||||||||||
| Adjusted general and administrative expenses | $ | 185 | $ | 200 | $ | 10 | $ | 15 | $ | 175 | $ | 185 | |||||||||||||||||||||||
1 Current guidance assumes a 2022 Brent price of $103.42 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $5.62 per mcf. CRC's share of production under PSCs decreases when commodity prices rise and increases when prices decline. | |||||||||||||||||||||||||||||||||||
2 CMB Expenses include start-up expenditures. | |||||||||||||||||||||||||||||||||||
Page 26
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