8-K
California Resources Corp (CRC)
View as plain text
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): March 11, 2021
_____________________
California Resources Corporation
(Exact Name of Registrant as Specified in its Charter)
| Delaware | 001-36478 | 46-5670947 | |
|---|---|---|---|
| (State or Other Jurisdiction of <br>Incorporation) | (Commission<br>File Number) | (IRS Employer <br>Identification No.) | |
| 27200 Tourney Road | |||
| Suite 200 | |||
| Santa Clarita | |||
| California | 91355 | ||
| (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:
☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐ 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. ☐
Item 2.02 Results of Operations and Financial Condition.
On March 11, 2021, 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, 2020. 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.
The information contained in this report and the exhibit 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 exhibit 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 Financial Statements and Exhibits
(d) Exhibits
| Exhibit No. | Description |
|---|---|
| 99.1 | Press Release dated March 11, 2021. |
| 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 | |
|---|---|
| /s/ Roy Pineci | |
| Name: | Roy Pineci |
| Title: | Senior Vice President |
DATED: March 11, 2021
Document
Exhibit 99.1
NEWS RELEASE
California Resources Corporation Announces Fourth Quarter 2020 and Full Year Results
Santa Clarita, March 11, 2021 - California Resources Corporation (NYSE: CRC), an independent California-based oil and natural gas exploration and production company, today reported fourth quarter and full year 2020 results. Operational and financial highlights were as follows:
2020 Fourth Quarter and Full Year Highlights
•For the full year of 2020, CRC reported net income of $1,871 million and an adjusted net loss attributable to common stock1 of $257 million, excluding unusual and infrequent items primarily related to CRC’s bankruptcy proceedings and asset impairments
•For the full year of 2020, reported net cash provided by operating activities of $106 million while generating free cash flow1 of $172 million, excluding $113 million of one time bankruptcy related fees
•For the full year of 2020, reported adjusted EBITDAX1 of $489 million with an adjusted EBITDAX margin1 of 28%
•For the fourth quarter of 2020, produced an average of 103,000 net barrels of oil equivalent (BOE) per day, including 63,000 barrels per day of oil and an average of 111,000 net BOE per day, including 69,000 barrels per day of oil for the full year 2020
•Exited 2020 with an average daily net production of 102,000 BOE per day, including 63,000 barrels per day of oil
•Decreased operating costs, on a per BOE basis, by 19% to $15.45 in 2020 from $19.16 in 2019
•Published third annual Sustainability Report showcasing positive progress on CRC's 2030 Sustainability Goals and secured a top score at CDP’s Leadership Level
•Completed a financial restructuring and emerged from Chapter 11 bankruptcy with a simplified balance sheet and ample liquidity
Other Highlights
•In January 2021, CRC further simplified its balance sheet by completing an offering of $600 million of 7.125% senior unsecured notes due 2026. The net proceeds of $590 million were used to repay in full CRC's Second Lien Term Loan and senior secured notes issued by its subsidiary Elk Hills Power, LLC. The remaining proceeds were used to pay down a portion of CRC's Revolving Credit Facility
•Consistent with the Company’s new strategic direction and low-cost operator focus, CRC has implemented a number of personnel-related cost reduction initiatives to further optimize its organizational structure. Excluding one-time severance charges, these personnel related changes are expected to reduce the compensation expense component of CRC’s 2021
Page 1
operating expenses by approximately $15 million per year and general and administrative expenses by approximately $50 million per year from its 2020 levels
Mac McFarland, CRC's Chairman and Interim Chief Executive Officer, commented, "We continued our strategic repositioning efforts, making progress on sustainable cost reductions and resuming prudent capital and maintenance spending. CRC will host a Strategy Day on March 18, 2021, and we look forward to providing further details of our full-scale business review and our strategic re-alignment at that time."
Fresh Start Accounting and Predecessor and Successor Periods
Upon emergence from Chapter 11 bankruptcy proceedings on October 27, 2020, CRC adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings. Under fresh start accounting, the reorganized entity is considered a new reporting entity. CRC applied fresh start accounting as of October 31, 2020, an accounting convenience date, and the reorganization value of the emerging entity was assigned to individual assets and liabilities based on their estimated relative fair values. As such, fresh start accounting was reflected on the Company's consolidated balance sheet as of October 31, 2020. As a result of the application of fresh start accounting and the effects of the implementation of the Plan of Reorganization, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.
Fourth Quarter 2020 Results
| Fourth Quarter | ||||||||
|---|---|---|---|---|---|---|---|---|
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ and shares in millions, except per share amounts) | 2020 | 2020 | 2020 | 2019 | ||||
| Statements of Operations: | ||||||||
| Revenues | ||||||||
| Total revenues | 152 | 149 | 301 | 610 | ||||
| Costs and Other | ||||||||
| Total costs and other | 258 | 151 | 409 | 508 | ||||
| Operating (loss) income | (106) | (2) | (108) | 102 | ||||
| Net (Loss) Income Attributable to Common Stock | $ | (123) | $ | 3,985 | $ | 3,862 | $ | (67) |
| Net (loss) income attributable to common stock per share - diluted 1 | $ | (1.48) | $ | 80.20 | $ | — | $ | (1.36) |
| Adjusted net income (loss)1 | $ | 28 | $ | (20) | $ | 8 | $ | 36 |
| Adjusted net income (loss) per share - diluted1 | $ | 0.34 | $ | (0.40) | $ | — | $ | 0.73 |
| Weighted-average common shares outstanding - diluted | 83.3 | 49.5 | — | 49.2 | ||||
| Adjusted EBITDAX1 | $ | 83 | $ | 33 | $ | 116 | $ | 308 |
Page 2
| Fourth Quarter | ||||||||
|---|---|---|---|---|---|---|---|---|
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ in millions) | 2020 | 2020 | 2020 | 2019 | ||||
| Cash Flow Data: | ||||||||
| Net cash (used) provided by operating activities | $ | (12) | $ | (23) | $ | (35) | $ | 136 |
| Net cash used by investing activities | $ | (7) | $ | (2) | $ | (9) | $ | (103) |
| Net cash (used) provided by financing activities | $ | (156) | $ | 106 | $ | (50) | $ | (38) |
Full Year 2020 Results
| Total Year | ||||||||
|---|---|---|---|---|---|---|---|---|
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ and shares in millions, except per share amounts) | 2020 | 2020 | 2020 | 2019 | ||||
| Statements of Operations: | ||||||||
| Revenues | ||||||||
| Total revenues | 152 | 1,407 | 1,559 | 2,634 | ||||
| Costs and Other | ||||||||
| Total costs and other | 258 | 3,186 | 3,444 | 2,205 | ||||
| Operating (loss) income | (106) | (1,779) | (1,885) | 429 | ||||
| Net (Loss) Income Attributable to Common Stock | $ | (123) | $ | 1,889 | $ | 1,766 | $ | (28) |
| Net (loss) income attributable to common stock per share - diluted | $ | (1.48) | $ | 40.42 | $ | — | $ | (0.57) |
| Adjusted net income (loss)1 | $ | 28 | $ | (285) | $ | (257) | $ | 70 |
| Adjusted net income (loss) per share - diluted1 | $ | 0.34 | $ | (2.98) | $ | — | $ | 1.40 |
| Weighted-average common shares outstanding - diluted | 83.3 | 49.6 | — | 49.2 | ||||
| Adjusted EBITDAX1 | $ | 83 | $ | 406 | $ | 489 | $ | 1,142 |
| Total Year | ||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ in millions) | 2020 | 2020 | 2020 | 2019 | ||||
| Cash Flow Data: | ||||||||
| Net cash (used) provided by operating activities | $ | (12) | $ | 118 | $ | 106 | $ | 676 |
| Net cash used by investing activities | $ | (7) | $ | (30) | $ | (37) | $ | (394) |
| Net cash (used) provided by financing activities | $ | (156) | $ | 98 | $ | (58) | $ | (282) |
Review of Operating and Financial Results
Total daily net production volumes decreased 16% from 123,000 BOE per day for the fourth quarter of 2019 to 103,000 BOE per day for the fourth quarter of 2020. The decrease from the same prior-year period over CRC's low to mid-teens natural decline rate was primarily due to 2,000 BOE per day of shut-in production driven by the collapse in commodity prices and power outages, lower capital investment, and reduction of well repair work. On an annual basis, total daily net production volumes decreased 13% year-over-year, from 128,000 BOE per day in 2019 to 111,000 BOE per day in 2020. The decrease from the same prior-year period was primarily due
Page 3
a reduced capital program, approximately 3,000 BOE per day of shut-in production, the full year impact of the Lost Hills divestiture and reduction of well repair work. Production sharing contracts in our Long Beach assets increased CRC's share of oil production by approximately 2,100 and 2,700 barrels per day in the fourth quarter and full year of 2020 compared to the same prior-year periods, respectively. CRC exited 2020 with average daily net production of 102,000 BOE per day, including 63,000 barrels per day of oil. See Attachment 2 for further information on production information.
Realized crude oil prices, including the effect of settled hedges, decreased by $25.82 per barrel from $70.21 in the fourth quarter of 2019 to $44.39 per barrel in the fourth quarter of 2020. On an annual basis, realized crude oil prices, including the effect of settled hedges, decreased by $25.12 per barrel from $68.65 in 2019 to $43.53 per barrel. Brent realized prices were lower in 2020 compared to the same prior-year period due to the combination of the supply increase caused by the Saudi-Russia price war that began earlier in the year and the continuation of severe demand decline caused by shelter-in-place orders related to the COVID-19 pandemic. Nevertheless, in 2020, CRC's oil realizations continued to favorably benefit from Brent linked pricing as compared to other U.S. benchmarks. See Attachment 5 for further information on realizations.
Adjusted EBITDAX1 for the fourth quarter of 2020 was $116 million and cash used in operating activities was $35 million. On an annual basis, adjusted EBITDAX1 was $489 million and cash provided by operating activities was $106 million. For the fourth quarter of 2020, free cash flow1 was ($6) million, excluding $39 million of one-time costs incurred relating to CRC's bankruptcy, after taking into account CRC's internally funded capital of $10 million. For the full year, free cash flow1 was $172 million, excluding $113 million of one-time bankruptcy related fees, after taking into account CRC's internally funded capital of $47 million.
| FREE CASH FLOW | ||||||||
|---|---|---|---|---|---|---|---|---|
| Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We have excluded one-time costs for legal and professional fees related to our bankruptcy proceedings during 2020 as a supplemental measure of our free cash flow. | ||||||||
| Fourth Quarter | Total Year | |||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ millions) | 2020 | 2019 | 2020 | 2019 | ||||
| Net cash provided by operating activities | $ | (35) | $ | 136 | $ | 106 | $ | 676 |
| Capital investments | (10) | (62) | (47) | (455) | ||||
| Free cash flow1 | (45) | 74 | 59 | 221 | ||||
| BSP funded capital | — | — | — | 48 | ||||
| Free cash flow, after internally funded capital1 | $ | (45) | $ | 74 | $ | 59 | $ | 269 |
| Professional fees related to our bankruptcy | 39 | — | 113 | — | ||||
| Free cash flow, excluding professional fees related to our bankruptcy1 | $ | (6) | $ | 74 | $ | 172 | $ | 269 |
Operating costs for the fourth quarter of 2020 were $165 million, compared to $211 million for the fourth quarter of 2019. For the full year 2020, operating costs were $625 million, compared to $895 million in 2019. The decrease was primarily due to efficiencies and streamlining of operations, reduced operating costs from shut-in wells as well as lower activity levels, such as downhole maintenance. Operating costs per BOE are presented below:
Page 4
| OPERATING COSTS PER BOE | ||||||||
|---|---|---|---|---|---|---|---|---|
| The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSC-type contracts. | ||||||||
| Fourth Quarter | Total Year | |||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ per Boe) | 2020 | 2019 | 2020 | 2019 | ||||
| Operating costs | $ | 17.42 | $ | 18.67 | $ | 15.45 | $ | 19.16 |
| Excess costs attributable to PSC-type contracts | (1.13) | (1.35) | (0.89) | (1.46) | ||||
| Operating costs, excluding effects of PSC-type contracts | $ | 16.29 | $ | 17.32 | $ | 14.56 | $ | 17.70 |
G&A expenses were $59 million for the fourth quarter of 2020, compared to $62 million in the same prior-year period. For the full year of 2020, G&A expenses were $252 million, compared to $290 million in 2019. The decrease in G&A expenses resulted from workforce reductions, cost saving efforts and a decline in spending across a number of cost categories. These savings were partially offset by the cost of obtaining additional directors and officers insurance related to the Chapter 11 cases, lower capitalized salary costs as a result of suspending the capital program beginning in March 2020 as well a slight increase in employee incentive awards due to changes to the variable portion of the incentive compensation program in May 2020, which had the effect of increasing CRC's cash-settled awards to target and achieving a higher target payout on performance metrics.
CRC reported taxes other than on income of $23 million for the fourth quarter of 2020, compared to $38 million for the same prior-year period. For the full year of 2020, CRC reported taxes other than on income of $144 million, compared to $157 million in 2019. The decrease primarily resulted from reduced emissions in 2020 as compared to 2019 due to lower activity levels, including shut-in wells, and better than expected market pricing on the purchase of greenhouse gas emissions credits. Exploration expense was $2 million and $11 million for the fourth quarter of 2020 and for the whole year, respectively, mostly due to limited exploration activity in 2020 as a result of the lower commodity price environment.
Total internally funded capital invested during the fourth quarter of 2020 was $10 million. For the full year of 2020, total capital invested was $140 million, of which $47 million was internally funded by CRC. CRC's JV partners Macquarie Infrastructure and Real Assets Inc. (MIRA) and Alpine Energy Capital, LLC (Alpine) invested an additional $1 million and $92 million, respectively, which are excluded from CRC's consolidated results.
Balance Sheet and Liquidity Update
In January 2021, CRC completed an offering of $600 million of 7.125% senior unsecured notes due 2026. The net proceeds of $590 million were used to repay in full the second lien term loan and all outstanding senior secured notes due 2027 issued by CRC's subsidiary Elk Hills Power, LLC, with the remaining $90 million used to pay down a portion of the Revolving Credit Facility. As of December 31, 2020, CRC had liquidity of $335 million, which consisted of $28 million in unrestricted cash and $307 million of available borrowing capacity under its Revolving Credit Facility. After giving effect to the January 2021 debt issuance discussed above, CRC would have had, on a pro forma basis, liquidity of $425 million as of December 31, 2020, which consisted of $28 million in unrestricted cash and $397 million of available borrowing capacity
Page 5
under its Revolving Credit Facility. As of March 01, 2021, CRC had an undrawn revolving credit facility, $125 million in letters of credit outstanding and liquidity of approximately $475 million.
Organization Changes
During the second half of 2020, CRC implemented organizational changes that resulted in a 12% reduction of overall headcount to approximately 1,100 employees. Subsequent to the quarter-end, CRC took steps to further align the cost structure with the objective to focus around core assets and cost performance. This included decisions to reduce the size of its management team and to realign several functions which resulted in further headcount and cost reductions. During the first quarter of 2021, CRC further reduced its headcount by an additional 9% to approximately 1,000 employees.
Excluding one-time severance charges, these personnel related changes are expected to reduce the compensation expense component of CRC’s 2021 operating expenses by approximately $15 million per year and general and administrative expenses by approximately $50 million per year from its 2020 levels.
Operational Update
In the fourth quarter of 2020, CRC operated no drilling rigs. The San Joaquin basin produced 74,000 net BOE per day. The Los Angeles basin produced 23,000 net BOE per day, the Ventura basin produced 3,000 net BOE per day and the Sacramento basin produced 3,000 net BOE per day.
2021 Capital Budget
CRC's capital program will be dynamic in response to oil market volatility while focusing on maintaining strong liquidity and maximizing free cash flow. The 2021 capital program will target reinvestment of approximately 50% of anticipated available cash flow from operations at current commodity prices. CRC's 2021 capital program is anticipated to be between $200 and $225 million, including approximately $40 million of mechanical integrity and midstream turnaround activities deferred from 2020 to 2021. The current plan anticipates CRC to gradually raise quarterly investment throughout the year if the commodity environment continues to strengthen. CRC will maintain the flexibility to adjust its capital program in response to declining market conditions.
Reserves
As of December 31, 2020, CRC had estimated proved reserves totaling 442 million BOE, of which 382 million BOE was proved developed and 60 million BOE was proved undeveloped. The estimated future net cash flows of our proved reserve volumes had a PV-10 value of $2.43 billion. These estimates were based on SEC pricing and the average realized prices for estimating CRC's proved reserves were $42.35 per barrel for oil, $26.42 per barrel for NGLs and $2.28 per Mcf for natural gas.
Page 6
| PV-10 AND STANDARDIZED MEASURE | ||
|---|---|---|
| The following table presents a reconciliation of the GAAP financial measure of Standardized Measure of discounted future net cash flows (Standardized Measure) to the non-GAAP financial measure of PV-10: | ||
| ($ millions) | December 31, 2020 | |
| Standardized Measure of discounted future net cash flows | $ | 1,932 |
| Present value of future income taxes discounted at 10% | 494 | |
| PV-10 of cash flows (*) | $ | 2,426 |
| (*) 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. |
Based on average realized prices of $55 per barrel of oil and $2.50 per Mcf for natural gas, CRC's estimated proved reserves would be 515 million BOE, including 441 million BOE of proved developed and 74 million BOE of proved undeveloped reserves. Management's internal estimate of PV-10 value at these prices would be approximately $4.75 billion2.
ESG Update
As a dependable and reliable energy producer in the State of California, in 2020, CRC maintained the highest CDP ranking among all U.S. oil and gas companies, tying for first with one other U.S.-based E&P with global operations, and released the third annual Sustainability report with expanded disclosures. Underscoring the Company's commitment to safe and responsible production, CRC's ESG performance and progress on its 2030 Sustainability Goals, which align with California’s climate goals toward carbon neutrality in accordance with the Paris Climate Accord, continue to be directly tied to the performance-based compensation of its executives, senior managers and employees. The new Board of Directors will continue to highlight, monitor and provide guidance on CRC ESG efforts, including a strong commitment to sustainability, HSE and community engagement.
Hedging Update as of February 28, 2021
CRC will utilize its hedging program to ensure strong cash flows in nearly any commodity price environment and will target approximately 80% of anticipated production. The current strategy includes a mix of swaps and options to ensure CRC’s ability to generate free cash flow and is also aligned with CRC’s reserve-based lending (RBL) requirements. See Attachment 7 for further information on CRC's current hedges.
2021 Strategy Day
On March 18, 2021, at 1 p.m. Eastern Time/10 a.m. Pacific Time, CRC will host a virtual Strategy Day to review the Company’s strategic repositioning, expected outcomes of the new strategic alignment and 2021 guidance. Participants can preregister here for the live webcast or access in the Investor Relations section of CRC.com the day of the event. A digital replay of the event will be archived for approximately 90 days and supplemental slides for the event will also be available in the Investor Relations section on www.crc.com.
Page 7
1 See Attachment 3 for the non-GAAP financial measures of adjusted EBITDAX, adjusted EBITDAX margin, operating costs per BOE (excluding effects of PSC-type contracts), adjusted net income (loss), discretionary cash flow and free cash flow, including reconciliations to their most directly comparable GAAP measure, where applicable.
2 GAAP does not prescribe a standardized measure of reserves on a basis other than SEC pricing. As such, no standardized measure of proved reserves using $55 per barrel for oil and $2.50 per Mcf for natural gas has been provided.
About California Resources Corporation
California Resources Corporation (CRC) is an independent oil and natural gas exploration and production company, applying complementary and integrated infrastructure to gather, process and market its production. Using advanced technology, CRC focuses on safely and responsibly supplying affordable energy.
Forward-Looking Statements
The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect CRC's expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding CRC's expectations as to its future:
•financial position, liquidity, cash flows and results of operations
•business prospects
•transactions and projects
•operating costs
•operations and operational results including production, hedging and capital investment
•budgets and maintenance capital requirements
•reserves
•type curves
•expected synergies from acquisitions and joint ventures
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While CRC believes assumptions or bases underlying its expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. CRC also believes third-party statements it cites are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:
•CRC's ability to execute its business plan post-emergence
•the volatility of commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices
•impact of CRC's recent emergence from bankruptcy on its business and relationships
•debt limitations on CRC's financial flexibility
•insufficient cash flow to fund planned investments, interest payments on CRC's debt, debt repurchases or changes to CRC's capital plan
•insufficient capital or liquidity, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors
•limitations on transportation or storage capacity and the need to shut-in wells
•inability to enter into desirable transactions including acquisitions, asset sales and joint ventures
Page 8
•CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations
•legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases (GHGs) or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of CRC products
•joint ventures and acquisitions and CRC's ability to achieve expected synergies
•the recoverability of resources and unexpected geologic conditions
•incorrect estimates of reserves and related future cash flows and the inability to replace reserves
•changes in business strategy
•production-sharing contracts' effects on production and unit operating costs
•the effect of CRC's stock price on costs associated with incentive compensation
•effects of hedging transactions
•equipment, service or labor price inflation or unavailability
•availability or timing of, or conditions imposed on, permits and approvals
•lower-than-expected production, reserves or resources from development projects, joint ventures or acquisitions, or higher-than-expected decline rates
•disruptions due to accidents, mechanical failures, power outages, transportation or storage constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
•pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19
•factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K available at www.crc.com.
Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
Contacts:
| Joanna Park (Investor Relations) 818-661-3731 <br>Joanna.Park@crc.com | Richard Venn (Media)<br><br>818-661-6014<br><br>Richard.Venn@crc.com |
|---|
Page 9
| Attachment 1 | ||||||||
|---|---|---|---|---|---|---|---|---|
| SUMMARY OF RESULTS | ||||||||
| Fourth Quarter | ||||||||
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ and shares in millions, except per share amounts) | 2020 | 2020 | 2020 | 2019 | ||||
| Statements of Operations: | ||||||||
| Revenues | ||||||||
| Oil and natural gas sales | $ | 237 | $ | 105 | $ | 342 | $ | 550 |
| Net derivative gain (loss) from commodity contracts | (141) | 16 | (125) | (28) | ||||
| Other revenue | ||||||||
| Trading revenue | 38 | 15 | 53 | 56 | ||||
| Electricity sales | 15 | 11 | 26 | 24 | ||||
| Other | 3 | 2 | 5 | 8 | ||||
| Total revenues | 152 | 149 | 301 | 610 | ||||
| Costs and Other | ||||||||
| Operating costs | 114 | 51 | 165 | 211 | ||||
| General and administrative expenses | 40 | 19 | 59 | 62 | ||||
| Depreciation, depletion and amortization | 34 | 32 | 66 | 114 | ||||
| Taxes other than on income | 10 | 13 | 23 | 38 | ||||
| Exploration expense | 1 | 1 | 2 | 4 | ||||
| Other expenses, net | ||||||||
| Trading costs | 24 | 11 | 35 | 31 | ||||
| Electricity cost of sales | 10 | 6 | 16 | 17 | ||||
| Transportation costs | 8 | 4 | 12 | 10 | ||||
| Other | 17 | 14 | 31 | 21 | ||||
| Total costs and other | 258 | 151 | 409 | 508 | ||||
| Operating (Loss) Income | (106) | (2) | (108) | 102 | ||||
| Non-Operating (Loss) Income | ||||||||
| Reorganization items, net | (3) | 3,994 | 3,991 | — | ||||
| Interest and debt expense, net | (11) | (6) | (17) | (90) | ||||
| Net gain on early extinguishment of debt | — | — | — | 18 | ||||
| Other non-operating expenses | (5) | 9 | 4 | (54) | ||||
| (Loss) Income Before Income Taxes | (125) | 3,995 | 3,870 | (24) | ||||
| Income tax provision | — | — | — | (1) | ||||
| Net (Loss) Income | (125) | 3,995 | 3,870 | (25) | ||||
| Net loss (income) attributable to noncontrolling interests | 2 | (10) | (8) | (42) | ||||
| Net (Loss) Income Attributable to Common Stock | $ | (123) | $ | 3,985 | $ | 3,862 | $ | (67) |
| Net (loss) income attributable to common stock per share - basic 1 | $ | (1.48) | $ | 80.20 | $ | — | $ | (1.36) |
| Net (loss) income attributable to common stock per share - diluted 1 | $ | (1.48) | $ | 80.20 | $ | — | $ | (1.36) |
| Adjusted net income (loss) | $ | 28 | $ | (20) | $ | 8 | $ | 36 |
| Adjusted net income (loss) per share - basic | $ | 0.34 | $ | (0.40) | $ | — | $ | 0.73 |
| Adjusted net income (loss) per share - diluted | $ | 0.34 | $ | (0.40) | $ | — | $ | 0.73 |
| Weighted-average common shares outstanding - basic | 83.3 | 49.5 | — | 49.1 | ||||
| Weighted-average common shares outstanding - diluted | 83.3 | 49.5 | — | 49.2 | ||||
| Adjusted EBITDAX | $ | 83 | $ | 33 | $ | 116 | $ | 308 |
| Effective tax rate | 0% | 0% | 0% | 4% |
Page 10
| Total Year | ||||||||
|---|---|---|---|---|---|---|---|---|
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ and shares in millions, except per share amounts) | 2020 | 2020 | 2020 | 2019 | ||||
| Statements of Operations: | ||||||||
| Revenues | ||||||||
| Oil and natural gas sales | $ | 237 | $ | 1,092 | $ | 1,329 | $ | 2,270 |
| Net derivative gain (loss) from commodity contracts | (141) | 91 | (50) | (59) | ||||
| Other revenue | ||||||||
| Trading revenue | 38 | 124 | 162 | 286 | ||||
| Electricity sales | 15 | 86 | 101 | 112 | ||||
| Other | 3 | 14 | 17 | 25 | ||||
| Total revenues | 152 | 1,407 | 1,559 | 2,634 | ||||
| Costs and Other | ||||||||
| Operating costs | 114 | 511 | 625 | 895 | ||||
| General and administrative expenses | 40 | 212 | 252 | 290 | ||||
| Depreciation, depletion and amortization | 34 | 328 | 362 | 471 | ||||
| Asset impairments | — | 1,736 | 1,736 | — | ||||
| Taxes other than on income | 10 | 134 | 144 | 157 | ||||
| Exploration expense | 1 | 10 | 11 | 29 | ||||
| Other expenses, net | ||||||||
| Trading costs | 24 | 78 | 102 | 201 | ||||
| Electricity cost of sales | 10 | 53 | 63 | 68 | ||||
| Transportation costs | 8 | 35 | 43 | 40 | ||||
| Other | 17 | 89 | 106 | 54 | ||||
| Total costs and other | 258 | 3,186 | 3,444 | 2,205 | ||||
| Operating (Loss) Income | (106) | (1,779) | (1,885) | 429 | ||||
| Non-Operating (Loss) Income | ||||||||
| Reorganization items, net | (3) | 4,060 | 4,057 | — | ||||
| Interest and debt expense, net | (11) | (206) | (217) | (383) | ||||
| Net gain on early extinguishment of debt | — | 5 | 5 | 126 | ||||
| Other non-operating expenses | (5) | (84) | (89) | (72) | ||||
| (Loss) Income Before Income Taxes | (125) | 1,996 | 1,871 | 100 | ||||
| Income tax provision | — | — | — | (1) | ||||
| Net (Loss) Income | (125) | 1,996 | 1,871 | 99 | ||||
| Net loss (income) attributable to noncontrolling interests | 2 | (107) | (105) | (127) | ||||
| Net (Loss) Income Attributable to Common Stock | $ | (123) | $ | 1,889 | $ | 1,766 | $ | (28) |
| Net (loss) income attributable to common stock per share - basic | $ | (1.48) | $ | 40.59 | $ | — | $ | (0.57) |
| Net (loss) income attributable to common stock per share - diluted | $ | (1.48) | $ | 40.42 | $ | — | $ | (0.57) |
| Adjusted net income (loss) | $ | 28 | $ | (285) | $ | (257) | $ | 70 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Adjusted net income (loss) per share - basic | $ | 0.34 | $ | (2.98) | $ | — | $ | 1.41 |
| Adjusted net income (loss) per share - diluted | $ | 0.34 | $ | (2.98) | $ | — | $ | 1.40 |
| Weighted-average common shares outstanding - basic | 83.3 | 49.4 | — | 49.0 | ||||
| Weighted-average common shares outstanding - diluted | 83.3 | 49.6 | — | 49.2 | ||||
| Adjusted EBITDAX | $ | 83 | $ | 406 | $ | 489 | $ | 1,142 |
| Effective tax rate | 0% | 0% | 0 | 1% |
Page 11
| Fourth Quarter | ||||||||
|---|---|---|---|---|---|---|---|---|
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ in millions) | 2020 | 2020 | 2020 | 2019 | ||||
| Cash Flow Data: | ||||||||
| Net cash (used) provided by operating activities | $ | (12) | $ | (23) | $ | (35) | $ | 136 |
| Net cash used by investing activities | $ | (7) | $ | (2) | $ | (9) | $ | (103) |
| Net cash (used) provided by financing activities | $ | (156) | $ | 106 | $ | (50) | $ | (38) |
| Total Year | ||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ($ in millions) | 2020 | 2020 | 2020 | 2019 | ||||
| Cash Flow Data: | ||||||||
| Net cash (used) provided by operating activities | $ | (12) | $ | 118 | $ | 106 | $ | 676 |
| Net cash used by investing activities | $ | (7) | $ | (30) | $ | (37) | $ | (394) |
| Net cash (used) provided by financing activities | $ | (156) | $ | 98 | $ | (58) | $ | (282) |
| Successor | Predecessor | |||||||
| --- | --- | --- | --- | --- | ||||
| December 31, | December 31, | |||||||
| ($ and shares in millions) | 2020 | 2019 | ||||||
| Selected Balance Sheet Data: | ||||||||
| Total current assets | $ | 329 | $ | 491 | ||||
| Property, plant and equipment, net | $ | 2,655 | $ | 6,352 | ||||
| Total current liabilities | $ | 473 | $ | 709 | ||||
| Long-term debt, net | $ | 597 | $ | 5,023 | ||||
| Other long-term liabilities | $ | 822 | $ | 720 | ||||
| Mezzanine equity | $ | — | $ | 802 | ||||
| Equity | $ | 1,182 | $ | (296) | ||||
| Outstanding shares | 83.3 | 49.2 |
Page 12
| DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Fourth Quarter | ||||||||||||||||||
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||||||||||
| ($ millions) | 2020 | 2020 | 2020 | 2019 | ||||||||||||||
| Non-cash derivative (loss) gain - excluding noncontrolling interest | $ | (138) | $ | 13 | $ | (125) | $ | (67) | ||||||||||
| Non-cash derivative (loss) gain - noncontrolling interest | (2) | — | (2) | (4) | ||||||||||||||
| Total non-cash changes | (140) | 13 | (127) | (71) | ||||||||||||||
| Net (payments) proceeds on settled commodity derivatives | (1) | 3 | 2 | 43 | ||||||||||||||
| Net derivative (loss) gain from commodity contracts | $ | (141) | $ | 16 | $ | (125) | $ | (28) | Total Year | |||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- | ||||||||||
| Successor | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||||||||||
| ($ millions) | 2020 | 2020 | 2020 | 2019 | ||||||||||||||
| Non-cash derivative (loss) gain - excluding noncontrolling interest | $ | (138) | $ | (19) | $ | (157) | $ | (166) | ||||||||||
| Non-cash derivative (loss) gain - noncontrolling interest | (2) | 2 | — | (4) | ||||||||||||||
| Total non-cash changes | (140) | (17) | (157) | (170) | ||||||||||||||
| Net (payments) proceeds on settled commodity derivatives | (1) | 108 | 107 | 111 | ||||||||||||||
| Net derivative (loss) gain from commodity contracts | $ | (141) | $ | 91 | $ | (50) | $ | (59) |
Page 13
| Attachment 2 | ||||
|---|---|---|---|---|
| PRODUCTION STATISTICS | ||||
| Fourth Quarter | ||||
| Net | Successor | Predecessor | Combined | Predecessor |
| Oil, NGLs and Natural Gas Production Per Day | 2020 | 2020 | 2020 | 2019 |
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 38 | 38 | 38 | 50 |
| Los Angeles Basin | 23 | 23 | 23 | 23 |
| Ventura Basin | 2 | 2 | 2 | 3 |
| Total | 63 | 63 | 63 | 76 |
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 12 | 13 | 13 | 15 |
| Total | 12 | 13 | 13 | 15 |
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 138 | 139 | 138 | 157 |
| Los Angeles Basin | 1 | 1 | 2 | 2 |
| Ventura Basin | 3 | 3 | 3 | 5 |
| Sacramento Basin | 23 | 19 | 20 | 26 |
| Total | 165 | 162 | 163 | 190 |
| Total Production (MBoe/d) | 103 | 103 | 103 | 123 |
| Fourth Quarter | ||||
| Gross Operated and Net Non-Operated | Successor | Predecessor | Combined | Predecessor |
| Oil, NGLs and Natural Gas Production Per Day | 2020 | 2020 | 2020 | 2019 |
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 44 | 45 | 45 | 54 |
| Los Angeles Basin | 28 | 27 | 28 | 31 |
| Ventura Basin | 3 | 3 | 2 | 4 |
| Total | 75 | 75 | 75 | 89 |
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 13 | 14 | 13 | 15 |
| Total | 13 | 14 | 13 | 15 |
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 148 | 149 | 148 | 161 |
| Los Angeles Basin | 8 | 8 | 8 | 10 |
| Ventura Basin | 3 | 4 | 4 | 5 |
| Sacramento Basin | 26 | 24 | 25 | 35 |
| Total | 185 | 185 | 185 | 211 |
| Total Production (MBoe/d) | 119 | 119 | 119 | 140 |
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 14
| Total Year | ||||
|---|---|---|---|---|
| Net | Successor | Predecessor | Combined | Predecessor |
| Oil, NGLs and Natural Gas Production Per Day | 2020 | 2020 | 2020 | 2019 |
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 38 | 42 | 42 | 52 |
| Los Angeles Basin | 23 | 25 | 24 | 24 |
| Ventura Basin | 2 | 3 | 3 | 4 |
| Total | 63 | 70 | 69 | 80 |
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 12 | 13 | 13 | 15 |
| Total | 12 | 13 | 13 | 15 |
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 138 | 147 | 145 | 162 |
| Los Angeles Basin | 1 | 2 | 2 | 2 |
| Ventura Basin | 3 | 4 | 4 | 5 |
| Sacramento Basin | 23 | 21 | 21 | 28 |
| Total | 165 | 174 | 172 | 197 |
| Total Production (MBoe/d) | 103 | 112 | 111 | 128 |
| Total Year | ||||
| --- | --- | --- | --- | --- |
| Gross Operated and Net Non-Operated | Successor | Predecessor | Combined | Predecessor |
| Oil, NGLs and Natural Gas Production Per Day | 2020 | 2020 | 2020 | 2019 |
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 44 | 49 | 48 | 56 |
| Los Angeles Basin | 28 | 30 | 29 | 32 |
| Ventura Basin | 3 | 3 | 3 | 5 |
| Total | 75 | 82 | 80 | 93 |
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 13 | 14 | 14 | 15 |
| Total | 13 | 14 | 14 | 15 |
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 148 | 157 | 155 | 164 |
| Los Angeles Basin | 8 | 9 | 9 | 9 |
| Ventura Basin | 3 | 4 | 4 | 5 |
| Sacramento Basin | 26 | 27 | 26 | 38 |
| Total | 185 | 197 | 194 | 216 |
| Total Production (MBoe/d) | 119 | 129 | 127 | 144 |
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 15
| Attachment 3 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS | ||||||||||
| Our results of operations, which are presented in accordance with U.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses certain non-GAAP measures to assess our financial condition, results of operations and cash flows. These measures are widely used by the industry, the investment community and our lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the effect of acquisition and development costs of our assets. These measures should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.<br><br><br><br>Below are additional disclosures regarding each of the non-GAAP measures reported in this press release, including reconciliations to their most directly comparable GAAP measure where applicable. | ADJUSTED NET INCOME (LOSS) | |||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- | ||
| Management uses a measure called adjusted net income (loss) to provide useful information to investors interested in comparing our core operations between periods and our performance to our peers. This measure is not meant to disassociate the effects of unusual, out-of-period and infrequent items affecting earnings from management's performance but rather is meant to provide useful information to investors interested in comparing our financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income (loss) attributable to common stock to the non-GAAP financial measure of adjusted net income (loss) and presents the GAAP financial measure of net income (loss) attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net income (loss) per diluted share. | ||||||||||
| Fourth Quarter | Total Year | |||||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||
| ($ millions, except per share amounts) | 2020 | 2019 | 2020 | 2019 | ||||||
| Net income (loss) | $ | 3,870 | $ | (25) | $ | 1,871 | $ | 99 | ||
| Net income attributable to noncontrolling interests | (8) | (42) | (105) | (127) | ||||||
| Net income (loss) attributable to common stock | 3,862 | (67) | 1,766 | (28) | ||||||
| Unusual, infrequent and other items: | ||||||||||
| Non-cash derivative loss (gain) from commodities, excluding noncontrolling interest | 125 | 67 | 157 | 166 | ||||||
| Non-cash derivative loss from interest rate contracts | — | — | — | 4 | ||||||
| Asset impairments | — | — | 1,736 | — | ||||||
| Reorganization items, net | (3,991) | — | (4,057) | — | ||||||
| Severance and termination costs | 5 | 45 | 15 | 47 | ||||||
| Incentive and retention award modifications | — | — | 4 | — | ||||||
| Net gain on early extinguishment of debt | — | (18) | (5) | (126) | ||||||
| Legal and professional fees related to our reorganization | — | — | 65 | — | ||||||
| Deficiency payment on pipeline delivery contract | — | — | 20 | — | ||||||
| Power plant maintenance | — | — | 7 | — | ||||||
| Write-off of deferred financing costs | — | — | 4 | |||||||
| Rig termination expenses | 2 | 1 | 5 | 3 | ||||||
| Ad valorem late payment penalties | — | — | 4 | — | ||||||
| Other, net | 5 | 8 | 22 | 4 | ||||||
| Total unusual, infrequent and other items | (3,854) | 103 | (2,023) | 98 | ||||||
| Adjusted net income (loss) attributable to common stock | $ | 8 | $ | 36 | $ | (257) | $ | 70 | ||
| Net income (loss) attributable to common stock per share - diluted | $ | — | $ | (1.36) | $ | — | $ | (0.57) | ||
| Adjusted net income (loss) per share - diluted | $ | — | $ | 0.73 | $ | — | $ | 1.40 |
Page 16
| FREE CASH FLOW | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We have excluded one-time costs for bankruptcy related fees during 2020 as a supplemental measure of our free cash flow. | ||||||||||||||||||
| Fourth Quarter | Total Year | |||||||||||||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||||||||||
| ($ millions) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||
| Net cash provided by operating activities | $ | (35) | $ | 136 | $ | 106 | $ | 676 | ||||||||||
| Capital investments | (10) | (62) | (47) | (455) | ||||||||||||||
| Free cash flow | (45) | 74 | 59 | 221 | ||||||||||||||
| BSP funded capital | — | — | — | 48 | ||||||||||||||
| Free cash flow, after internally funded capital | $ | (45) | $ | 74 | $ | 59 | $ | 269 | ||||||||||
| One-time bankruptcy related fees | 39 | — | 113 | — | ||||||||||||||
| Free cash flow, excluding one-time bankruptcy related fees | $ | (6) | $ | 74 | $ | 172 | $ | 269 | 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. | ||||||||||||||||||
| Fourth Quarter | Total Year | |||||||||||||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||||||||||
| ($ millions, except per BOE amounts) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||
| Net (loss) income | $ | 3,870 | $ | (25) | $ | 1,871 | $ | 99 | ||||||||||
| Interest and debt expense, net | 17 | 90 | 217 | 383 | ||||||||||||||
| Depreciation, depletion and amortization | 66 | 114 | 362 | 471 | ||||||||||||||
| Exploration expense | 2 | 4 | 11 | 29 | ||||||||||||||
| Unusual, infrequent and other items (a) | (3,854) | 103 | (2,023) | 98 | ||||||||||||||
| Non-cash items | ||||||||||||||||||
| Accretion expense | 11 | 8 | 41 | 36 | ||||||||||||||
| Stock-settled compensation | 1 | 3 | 6 | 13 | ||||||||||||||
| Post-retirement medical and pension | 1 | 5 | 4 | 8 | ||||||||||||||
| Other non-cash items | 2 | 6 | — | 5 | ||||||||||||||
| Adjusted EBITDAX | $ | 116 | $ | 308 | $ | 489 | $ | 1,142 | ||||||||||
| Net cash provided by operating activities | $ | (35) | $ | 136 | $ | 106 | $ | 676 | ||||||||||
| Cash interest | 15 | 139 | 95 | 439 | ||||||||||||||
| Exploration expenditures | 2 | 3 | 11 | 18 | ||||||||||||||
| Working capital changes | 134 | 30 | 277 | 9 | ||||||||||||||
| Adjusted EBITDAX | $ | 116 | $ | 308 | $ | 489 | $ | 1,142 | ||||||||||
| Adjusted EBITDAX per Boe | $ | 12.25 | $ | 27.25 | $ | 12.09 | $ | 24.45 | ||||||||||
| (a) See Adjusted Net Income (Loss) reconciliation. |
Page 17
| DISCRETIONARY CASH FLOW | |||||||
|---|---|---|---|---|---|---|---|
| We define discretionary cash flow as the cash available after distributions to noncontrolling interest holders and cash interest, excluding the effect of working capital changes but before our internal capital investment. Management uses discretionary cash flow as a measure of the availability of cash to reduce debt or fund investments. | |||||||
| Total Year | |||||||
| Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||
| ( millions) | 2019 | 2020 | 2019 | ||||
| Adjusted EBITDAX | 116 | $ | 308 | $ | 489 | $ | 1,142 |
| Cash interest | (139) | (95) | (439) | ||||
| Distributions paid to noncontrolling interest holders: | |||||||
| BSP | (16) | (64) | (71) | ||||
| Ares | (20) | (70) | (80) | ||||
| Discretionary cash flow (1) | 62 | $ | 133 | $ | 260 | $ | 552 |
| (1) Cash used for asset retirement obligations and idle well testing would have reduced Discretionary Cash Flow by 9 million and 8 million for the three months ended December 31, 2020 and 2019, respectively and 17 million and 26 million for the years ended December 31, 2020 and 2019, respectively.. |
All values are in US Dollars.
| ADJUSTED EBITDAX MARGIN | ||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Management uses adjusted EBITDAX margin as a measure of profitability between periods and this measure is generally used by analysts for comparative purposes within the industry. | ||||||||||||||||||||||
| Fourth Quarter | Total Year | |||||||||||||||||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||||||||||||||
| ($ millions) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||
| Total revenues | $ | 301 | $ | 610 | $ | 1,559 | $ | 2,634 | ||||||||||||||
| Non-cash derivative loss | 127 | 71 | 157 | 170 | ||||||||||||||||||
| Revenues, excluding non-cash derivative gains and losses | $ | 428 | $ | 681 | $ | 1,716 | $ | 2,804 | ||||||||||||||
| Adjusted EBITDAX margin | 27 | % | 45 | % | 28 | % | 41 | % | OPERATING COSTS PER BOE | |||||||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- | ||||||||||||||
| The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSC-type contracts. | ||||||||||||||||||||||
| Fourth Quarter | Total Year | |||||||||||||||||||||
| Combined<br>(Non-GAAP) | Predecessor | Combined<br>(Non-GAAP) | Predecessor | |||||||||||||||||||
| ($ per Boe) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||
| Operating costs | $ | 17.42 | $ | 18.67 | $ | 15.45 | $ | 19.16 | ||||||||||||||
| Excess costs attributable to PSC-type contracts | (1.13) | (1.35) | (0.89) | (1.46) | ||||||||||||||||||
| Operating costs, excluding effects of PSC-type contracts | $ | 16.29 | $ | 17.32 | $ | 14.56 | $ | 17.70 |
Page 18
| Attachment 4 | ||||||||
|---|---|---|---|---|---|---|---|---|
| CAPITAL INVESTMENTS | ||||||||
| Fourth Quarter | ||||||||
| Successor | Predecessor | Combined | Predecessor | |||||
| ($ millions) | 2020 | 2020 | 2020 | 2019 | ||||
| Internally funded capital | $ | 7 | $ | 3 | $ | 10 | $ | 62 |
| Capital investments not included on our financial statements: | ||||||||
| MIRA funded capital | — | — | — | 13 | ||||
| Alpine funded capital | (1) | — | (1) | 71 | ||||
| Total capital program | $ | 6 | $ | 3 | $ | 9 | $ | 146 |
| Total Year | ||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Successor | Predecessor | Combined | Predecessor | |||||
| ($ millions) | 2020 | 2020 | 2020 | 2019 | ||||
| Internally funded capital | $ | 7 | $ | 40 | $ | 47 | $ | 455 |
| Capital investments not included on our financial statements: | ||||||||
| MIRA funded capital | — | 1 | 1 | 23 | ||||
| Alpine funded capital | (1) | 93 | 92 | 134 | ||||
| Total capital program | $ | 6 | $ | 134 | $ | 140 | $ | 612 |
Page 19
| Attachment 5 | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| PRICE STATISTICS | ||||||||||||
| Fourth Quarter | ||||||||||||
| Successor | Predecessor | Combined | Predecessor | |||||||||
| 2020 | 2020 | 2020 | 2019 | |||||||||
| Realized Prices | ||||||||||||
| Oil with hedge ($/Bbl) | $ | 45.37 | $ | 42.45 | $ | 44.39 | $ | 70.21 | ||||
| Oil without hedge ($/Bbl) | $ | 45.65 | $ | 40.59 | $ | 43.94 | $ | 64.22 | ||||
| NGLs ($/Bbl) | $ | 38.00 | $ | 30.57 | $ | 35.45 | $ | 33.81 | ||||
| Natural gas ($/Mcf) | $ | 3.21 | $ | 2.68 | $ | 3.03 | $ | 3.00 | ||||
| Index Prices | ||||||||||||
| Brent oil ($/Bbl) | $ | 47.10 | $ | 41.52 | $ | 45.24 | $ | 62.50 | ||||
| WTI oil ($/Bbl) | $ | 44.21 | $ | 39.55 | $ | 42.66 | $ | 56.96 | ||||
| NYMEX gas ($/MMBtu) | $ | 2.86 | $ | 2.28 | $ | 2.66 | $ | 2.50 | ||||
| Realized Prices as Percentage of Index Prices | ||||||||||||
| Oil with hedge as a percentage of Brent | 96 | % | 102 | % | 98 | % | 112 | % | ||||
| Oil without hedge as a percentage of Brent | 97 | % | 98 | % | 97 | % | 103 | % | ||||
| Oil with hedge as a percentage of WTI | 103 | % | 107 | % | 104 | % | 123 | % | ||||
| Oil without hedge as a percentage of WTI | 103 | % | 103 | % | 103 | % | 113 | % | ||||
| NGLs as a percentage of Brent | 81 | % | 74 | % | 78 | % | 54 | % | ||||
| NGLs as a percentage of WTI | 86 | % | 77 | % | 83 | % | 59 | % | ||||
| Natural gas as a percentage of NYMEX | 112 | % | 118 | % | 114 | % | 120 | % | ||||
| Total Year | ||||||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- | ||||
| Successor | Predecessor | Combined | Predecessor | |||||||||
| 2020 | 2020 | 2020 | 2019 | |||||||||
| Realized Prices | ||||||||||||
| Oil with hedge ($/Bbl) | $ | 45.37 | $ | 43.19 | $ | 43.53 | $ | 68.65 | ||||
| Oil without hedge ($/Bbl) | $ | 45.65 | $ | 41.21 | $ | 41.89 | $ | 64.83 | ||||
| NGLs ($/Bbl) | $ | 38.00 | $ | 25.70 | $ | 27.63 | $ | 31.71 | ||||
| Natural gas ($/Mcf) | $ | 3.21 | $ | 2.11 | $ | 2.28 | $ | 2.87 | ||||
| Index Prices | ||||||||||||
| Brent oil ($/Bbl) | $ | 47.10 | $ | 42.43 | $ | 43.21 | $ | 64.18 | ||||
| WTI oil ($/Bbl) | $ | 44.21 | $ | 38.44 | $ | 39.40 | $ | 57.03 | ||||
| NYMEX gas ($/MMBtu) | $ | 2.86 | $ | 1.95 | $ | 2.10 | $ | 2.67 |
`
| Realized Prices as Percentage of Index Prices | ||||||||
|---|---|---|---|---|---|---|---|---|
| Oil with hedge as a percentage of Brent | 96 | % | 102 | % | 101 | % | 107 | % |
| Oil without hedge as a percentage of Brent | 97 | % | 97 | % | 97 | % | 101 | % |
| Oil with hedge as a percentage of WTI | 103 | % | 112 | % | 110 | % | 120 | % |
| Oil without hedge as a percentage of WTI | 103 | % | 107 | % | 106 | % | 114 | % |
| NGLs as a percentage of Brent | 81 | % | 61 | % | 64 | % | 49 | % |
| NGLs as a percentage of WTI | 86 | % | 67 | % | 70 | % | 56 | % |
| Natural gas as a percentage of NYMEX | 112 | % | 108 | % | 109 | % | 107 | % |
Page 20
| Attachment 6 | |||||
|---|---|---|---|---|---|
| TOTAL YEAR 2020 DRILLING ACTIVITY | |||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||
| Wells Drilled | Basin | Basin | Basin | Basin | Total |
| Development Wells | |||||
| Primary | 48 | — | — | — | 48 |
| Waterflood | 2 | 4 | — | — | 6 |
| Steamflood | — | — | — | — | — |
| Unconventional | 18 | — | — | — | 18 |
| Total | 68 | 4 | — | — | 72 |
| Total (1) | 68 | 4 | — | — | 72 |
| San Joaquin | Los Angeles | Ventura | Sacramento | ||
| Wells Drilled | Basin | Basin | Basin | Basin | Total |
| CRC | 3 | 4 | — | — | 7 |
| Alpine | 65 | — | — | — | 65 |
| Total (1) | 68 | 4 | — | — | 72 |
| There were no wells drilled in the fourth quarter of 2020. | |||||
| (1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled. |
Page 21
| Attachment 7 | ||||||
|---|---|---|---|---|---|---|
| HEDGES - AS OF FEBRUARY 28, 2021 | ||||||
| January - | ||||||
| Q1 2021 | Q2 2021 | Q3 2021 | Q4 2021 | 2022 | October 2023 | |
| Sold Calls: | ||||||
| Barrels per day | 19,028 | 33,537 | 36,362 | 36,700 | 30,783 | 17,758 |
| Weighted-average Brent price per barrel | $47.88 | $48.73 | $50.31 | $60.70 | $59.37 | $58.01 |
| Purchased Puts: | ||||||
| Barrels per day | 39,148 | 37,872 | 36,617 | 35,483 | 30,783 | 17,758 |
| Weighted-average Brent price per barrel | $41.88 | $40.00 | $40.00 | $40.00 | $40.00 | $40.00 |
| Sold Puts: | ||||||
| Barrels per day | 15,659 | 15,149 | 14,647 | 14,193 | 3,042 | — |
| Weighted-average Brent price per barrel | $35.97 | $31.41 | $30.00 | $32.00 | $32.00 | — |
| Swaps: | ||||||
| Barrels per day | 8,524 | 9,639 | 9,063 | 8,922 | 6,576 | 5,919 |
| Weighted-average Brent price per barrel | $44.54 | $46.35 | $47.18 | $48.57 | $46.29 | $47.57 |
| The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the BSP JV could affect the timing of the redemption of BSP's preferred interest. |
Page 22