California Resources Corp - Quarter Report: 2021 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2021

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission file number 001-36478

California Resources Corporation

(Exact name of registrant as specified in its charter)


Delaware						46-5670947
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

27200 Tourney Road, Suite 200

Santa Clarita, California 91355

(Address of principal executive offices) (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange 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 (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-Accelerated Filer

☑

Smaller Reporting Company

☑

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☑ Yes ☐ No

Indicate the number of shares outstanding for each of the issuer's classes of common stock, as of the last practicable date.

The number of shares of common stock outstanding as of April 30, 2021 was 83,319,660.

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements (unaudited)	2
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income (Loss)	4
	Condensed Consolidated Statements of Equity	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to the Condensed Consolidated Financial Statements	7
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
	General	21
	Business Environment and Industry Outlook	22
	Operations	23
	Seasonality	25
	Fixed and Variable Costs	25
	Production and Prices	26
	Statements of Operations Analysis	28
	Liquidity and Capital Resources	31
	2021 Capital Program	33
	Lawsuits, Claims, Commitments and Contingencies	34
	Significant Accounting and Disclosure Changes	34
	Forward-Looking Statements	35
Item 3	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4	Controls and Procedures	37

Part II
Item 1	Legal Proceedings	38
Item 1A	Risk Factors	38
Item 5	Other Disclosures	38
Item 6	Exhibits	39

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of March 31, 2021 and December 31, 2020

(dollars and shares in millions, except par value)


	Successor
	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash	$	130	$	28
Trade receivables	201		177
Inventories	59		61
Other current assets	71		63
Total current assets	461		329
PROPERTY, PLANT AND EQUIPMENT	2,711		2,689
Accumulated depreciation, depletion and amortization	(86)		(34)
Total property, plant and equipment, net	2,625		2,655
OTHER ASSETS	94		90
TOTAL ASSETS	$	3,180	$	3,074


CURRENT LIABILITIES



Accounts payable	213		212
Accrued liabilities	409		261
Total current liabilities	622		473
LONG-TERM DEBT, NET	588		597

OTHER LONG-TERM LIABILITIES	889		822



STOCKHOLDERS' EQUITY
Preferred stock (20 shares authorized at $0.01 par value) no shares outstanding at March 31, 2021 and December 31, 2020	—		—
Common stock (200 shares authorized at $0.01 par value) outstanding shares (83.3 at March 31, 2021 and December 31, 2020)	1		1
Additional paid-in capital	1,270		1,268
Accumulated deficit	(217)		(123)
Accumulated other comprehensive loss	(8)		(8)
Total equity attributable to common stock	1,046		1,138
Equity attributable to noncontrolling interests	35		44
Total stockholders' equity	1,081		1,182
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,180	$	3,074

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three months ended March 31, 2021 and 2020

(dollars in millions, except per share data)


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
REVENUES
Oil, natural gas and NGL sales	$	432	$	430
Net derivative (loss) gain from commodity contracts	(213)		79
Trading revenue	98		45
Electricity sales	33		13
Other revenue	13		6
Total revenues	363		573

COSTS
Operating costs	164		192
General and administrative expenses	48		60
Depreciation, depletion and amortization	52		119
Asset impairments	3		1,736
Taxes other than on income	40		41
Exploration expense	2		5
Trading costs	61		24
Electricity cost of sales	24		16
Transportation costs	12		13
Other expenses, net	30		16
Total costs	436		2,222

OPERATING LOSS	(73)		(1,649)

NON-OPERATING (LOSS) INCOME
Reorganization items	(2)		—
Interest and debt expense, net	(13)		(87)
Net (loss) gain on early extinguishment of debt	(2)		5
Gain on asset divestitures	2		—
Other non-operating expenses	(1)		(14)
LOSS BEFORE INCOME TAXES	(89)		(1,745)
Income tax	—		—
NET LOSS	(89)		(1,745)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	—		(30)
Stockholders' equity	(5)		(21)
Net income attributable to noncontrolling interests	(5)		(51)
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(94)	$	(1,796)

Net loss attributable to common stock per share
Basic	$	(1.13)	$	(36.43)
Diluted	$	(1.13)	$	(36.43)

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income (Loss)

For the three months ended March 31, 2021 and 2020

(dollars in millions)


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
Net loss	$	(89)	$	(1,745)
Net income attributable to noncontrolling interests	(5)		(51)


Comprehensive loss attributable to common stock	$	(94)	$	(1,796)

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three months ended March 31, 2021 and 2020

(dollars in millions)


	Three months ended March 31, 2021 (Successor)
	Common Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, December 31, 2020	$	1	$	1,268	$	(123)	$	(8)	$	1,138	$	44	$	1,182
Net (loss) income(a)	—		—		(94)		—		(94)		5		(89)

Distributions to noncontrolling interest holders	—		—		—		—		—		(14)		(14)
Share-based compensation	—		2		—		—		2		—		2






Balance, March 31, 2021	$	1	$	1,270	$	(217)	$	(8)	$	1,046	$	35	$	1,081


	Three months ended March 31, 2020 (Predecessor)
	Common Stock		Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity		Redeemable Noncontrolling Interests(b)
Balance, December 31, 2019	$	—	$	5,004	$	(5,370)	$	(23)	(389)		$	93	$	(296)	$	802
Net (loss) income(a)	—		—		(1,796)		—		(1,796)		21		(1,775)		30
Contributions from noncontrolling interest holders			—		—		—		—				—		2
Distributions to noncontrolling interest holders	—		—		—		—		—		(26)		(26)		(18)
Share-based compensation, net	—		2		—		—		2		—		2		—






Balance, March 31, 2020	$	—	$	5,006	$	(7,166)	$	(23)	$	(2,183)	$	88	$	(2,095)	$	816

(a)For the three months ended March 31, 2020, we allocated $51 million of net income to noncontrolling interest holders, of which $21 million was included in stockholders' equity and $30 million was included in mezzanine equity on our condensed consolidated balance sheet. The remaining net loss of $1,796 million for the three months ended March 31, 2020 was attributed to holders of our common stock and included in stockholders' equity on our condensed consolidated balance sheet. For the three months ended March 31, 2021, we allocated $5 million of net income to noncontrolling interest holders, with the remaining $94 million of net loss attributed to holders of our common stock, both of which were included in stockholders' equity on our condensed consolidated balance sheet.

(b)Redeemable noncontrolling interests are reported in mezzanine equity on our condensed consolidated balance sheets in Predecessor periods. See Note 7 Joint Ventures for more information about our noncontrolling interests in the Ares and Elk Hills Carbon joint ventures.

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

For the three months ended March 31, 2021 and 2020

(dollars in millions)


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(89)	$	(1,745)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	52		119
Asset impairments	3		1,736
Net derivative loss (gain) from commodity contracts	213		(79)
Net (payments) proceeds from settled commodity derivatives	(39)		98
Net loss (gain) on early extinguishment of debt	2		(5)
Amortization of deferred gain	—		(17)
Gain on asset divestiture	(2)		—



Other non-cash charges to income, net	7		8
Changes in operating assets and liabilities, net	—		113
Net cash provided by operating activities	147		228

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(27)		(30)
Changes in accrued capital investments	5		(19)
Proceeds from asset divestitures	2		41

Other	—		(4)
Net cash used in investing activities	(20)		(12)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from Revolving Credit Facility	16		—
Repayments of Revolving Credit Facility	(115)		—
Proceeds from 2014 Revolving Credit Facility	—		449
Repayments of 2014 Revolving Credit Facility	—		(459)
Proceeds from Senior Notes	600		—
Debt repurchases	—		(3)
Debt issuance costs	(12)		—
Repayment of Second Lien Term Loan	(200)		—
Repayment of EHP Notes	(300)		—
Repayment of 2020 Senior Notes	—		(100)
Contributions from noncontrolling interest holders	—		2
Distributions paid to noncontrolling interest holders	(14)		(44)

Shares cancelled for taxes	—		(1)
Net cash used in financing activities	(25)		(156)
Increase in cash	102		60
Cash—beginning of period	28		17
Cash—end of period	$	130	$	77

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

March 31, 2021

NOTE 1 BASIS OF PRESENTATION

We are an independent oil and natural gas exploration and production company operating properties exclusively within California.

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

In the opinion of our management, the accompanying unaudited financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our financial position, results of operations, comprehensive income, equity and cash flows for all periods presented. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas producing activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our condensed consolidated financial statements.

We have prepared this report in accordance with generally accepted accounting principles (GAAP) in the United States and the rules and regulations of the U.S. Securities and Exchange Commission applicable to interim financial information which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the information presented not misleading.

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Actual results could differ. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of our condensed consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report).

Restructuring and Organization Changes

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 proceedings on October 27, 2020. In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020. On December 31, 2020, our former President, Chief Executive Officer and director Todd A. Stevens departed and Mark A. (Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors. On March 22, 2021, the Board of Directors appointed Mr. McFarland as President and Chief Executive Officer on a permanent basis. On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr. McFarland as the Chair of our Board of Directors. Mr. McFarland will continue to serve as a director.

In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions. We recorded a restructuring charge of $14 million for the three months ended March 31, 2021, which is included in other expenses, net on our condensed consolidated statement of operations. As of March 31, 2021, our remaining liability for workforce reductions which occurred in 2020 and during the first quarter of 2021 is $16 million, which is included in accrued liabilities on our condensed consolidated balance sheet.

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

We qualified for and adopted fresh start accounting upon emergence from bankruptcy at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

We adopted new accounting guidance on current expected credit losses on January 1, 2020, using a modified retrospective approach to the first period in which the guidance was effective. The new rules changed the measurement of credit losses for financial assets and certain other instruments, including trade and other receivables with a right to receive cash, and require the use of a new forward-looking expected loss model that results in the earlier recognition of an allowance for losses. The adoption of these new rules did not have a significant impact on our condensed consolidated financial statements.

NOTE 3 OTHER INFORMATION

Other current assets — Other current assets consisted of the following:


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Amounts due from joint interest partners	$	44	$	42
Amounts due from counterparties on derivative contracts	8		—
Prepaid expenses	18		20
Other	1		1
Other current assets	$	71	$	63

Accrued liabilities — Accrued liabilities consisted of the following:


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Accrued employee-related costs	$	63	$	72
Accrued taxes other than on income	44		36
Asset retirement obligations	50		50
Accrued interest	10		1
Lease liability	10		7
Fair value of derivative contracts	151		50
Amounts due to counterparties on derivative contracts	44		21
Other	37		24
Accrued liabilities	$	409	$	261

Other long-term liabilities — Other long-term liabilities included the following:


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Asset retirement obligations	$	546	$	547
Deferred compensation and postretirement	180		184
Lease liability	34		35
Fair value of derivative contracts	86		6
Amounts due to counterparties on derivative contracts	24		31
Other	19		19
Other long-term liabilities	$	889	$	822

Supplemental Cash Flow Information

We did not make U.S. federal and state income tax payments during the three months ended March 31, 2021 and 2020. Interest paid, net of capitalized amounts, totaled $2 million and $45 million for the three months ended March 31, 2021 and 2020, respectively. Cash paid for reorganization items during the three months ended March 31, 2021 was $2 million.

Fair Value of Financial Instruments

The carrying amounts of cash and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 5 Debt for the fair value of our debt. Refer to Note 14 Asset Impairments for impairment charges related to our long-lived assets.

NOTE 4 INVENTORIES

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods predominantly comprise oil and natural gas liquids (NGLs), which are valued at the lower of cost or net realizable value. Inventories, by category, are as follows:


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Materials and supplies	$	57	$	58
Finished goods	2		3
Inventories	$	59	$	61

NOTE 5 DEBT

As of March 31, 2021 and December 31, 2020, our long-term debt consisted of the following:


	Successor
	March 31,		December 31,
	2021		2020		Interest Rate	Maturity
	(in millions)

Revolving Credit Facility	$	—	$	99	LIBOR plus 3%-4% ABR plus 2%-3%	April 29, 2024

Second Lien Term Loan	—		200		LIBOR plus 9%-10.5% ABR plus 8%-9.5%	October 27, 2025

EHP Notes	—		300		6%	October 27, 2027
Senior Notes	600		—		7.125%	February 1, 2026
Principal Amount	$	600	$	599
Unamortized debt issuance costs	(12)		(2)
Long-term debt, net	$	588	$	597

Revolving Credit Facility

On October 27, 2020, we entered into a Credit Agreement with Citibank, N.A., as administrative agent, and certain other lenders. This credit agreement currently consists of a $492 million senior revolving loan facility (Revolving Credit Facility), which we are permitted to increase if we obtain additional commitments from new or existing lenders. Our aggregate commitment was $540 million as of March 31, 2021, which was automatically reduced to $492 million in April 2021 pursuant to the terms of our Revolving Credit Facility. Our Revolving Credit Facility also includes a sub-limit of $200 million for the issuance of letters of credit. The letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

The borrowing base is redetermined around April and October of each year and was most recently set at $1.2 billion in May 2021. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitment described above.

As of March 31, 2021 and April 30, 2021, our availability for borrowing under the Revolving Credit facility was as follows:


	Successor
	March 31,		April 30,
	2021		2021
	(in millions)
Borrowing capacity	$	540	$	492
Letters of credit outstanding	(125)		(125)
Total availability	$	415	$	367

On May 7, 2021, we amended the Revolving Credit Facility to:

•increase our borrowing base from $1.167 billion to $1.2 billion;

•evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million;

•increase our capacity to make certain restricted payments;

•reduce the minimum amount of hedges that we are required to maintain for a rolling 24 month period on reasonably anticipated forecasted crude oil production from 50% to 33% so long as our total net leverage ratio is less than 2.00:1.00; and

•increase our maximum hedging limitation to 85% (and permit purchased puts and floors up to 100%) of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids for a 48-month period.

Senior Notes

On January 20, 2021, we completed an offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and EHP Notes, with the remainder used to repay substantially all of the then outstanding borrowings under our Revolving Credit Facility. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Term Loan and EHP Notes. We recognized a $2 million loss on extinguishment of debt, including unamortized debt issuance costs, associated with these repayments.

Security – Our Senior Notes are general unsecured obligations which are guaranteed on a senior unsecured basis by certain of our material subsidiaries.

Redemption – Prior to February 1, 2023, we may elect to redeem up to 35% of the aggregate principal amount of our Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 107% of the aggregate amount of the Senior Notes redeemed, plus accrued and unpaid interest. In addition, prior to February 1, 2023, we may redeem the Senior Notes at a “make whole” premium plus accrued and unpaid interest. On or after February 1, 2023, we may redeem the Senior Notes at any time prior to the maturity date at a redemption price equal to (i) 104% of the principal amount if redeemed in the twelve months beginning February 1, 2023, (ii) 102% of the principal amount if redeemed in the twelve months beginning February 1, 2024 and (iii) 100% of the principal amount if redeemed after February 1, 2025, in each case plus accrued and unpaid interest.

Other Covenants – Our Senior Notes include covenants that, among other things, restrict our ability to incur additional indebtedness, issue preferred stock, grant liens, make asset sales and investments, repay existing indebtedness, make subsidiary distributions and enter into transactions that would result in fundamental changes.

Events of Default and Change of Control – Our Senior Notes provide for certain triggering events, including upon a change of control, as defined in the indenture, that would require us to repurchase all or any part of the Senior Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

Other

At March 31, 2021, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility and Senior Notes.

Predecessor Note Repurchases

In the first quarter of 2020, we repurchased $7 million in face value of our Second Lien Notes for $3 million in cash resulting in a pre-tax gain of $5 million, including the effect of unamortized deferred gain and issuance costs. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Notes.

Fair Value

We estimate that the fair value of our variable rate debt approximates its carrying value because the interest rate approximates current market rates. As shown in the table below, we estimated the fair value of our fixed rate Senior Notes based on observable inputs (Level 1) and the fair value of our EHP Notes with no observable inputs (Level 3).


	Successor
	March 31,		December 31,
	2021		2020
	(in millions)
Variable rate debt	$	—	$	299
Fixed rate debt

Senior Notes	611		—
EHP Notes	—		300
Fair Value of Long-Term Debt	$	611	$	599

NOTE 6 JOINT VENTURES

The following is a summary of our current consolidated joint venture arrangements:

BSP JV

In February 2017, we entered into a development joint venture (JV) with Benefit Street Partners (BSP) to develop certain oil and natural gas assets in exchange for a preferred interest in the BSP JV. BSP is entitled to preferred distributions and, if it receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. BSP has invested $200 million to date, before transaction costs. Our condensed consolidated results reflect the operations of our development JV with BSP, with BSP's preferred interest reported in equity on our condensed consolidated balance sheets and BSP’s share of net income (loss) reported in net income attributable to noncontrolling interests on our condensed consolidated statements of operations for all periods presented. Distributions to our joint venture partner are reported as financing cash outflows on our condensed consolidated statements of cash flows for all periods presented.

Elk Hills Carbon JV

In January 2020, we entered into an agreement with OGCI Climate Investments LLP (OGCI) to determine the technical and economic feasibility of retrofitting the Elk Hills power plant with a post-combustion, carbon-capture system, which includes a front-end engineering design (FEED) scope and study. The project received financial assistance from the U.S. Department of Energy and project participants include us, Electric Power Research Institute (EPRI), and Fluor Corporation. We formed a joint venture with OGCI called Elk Hills Carbon LLC (Elk Hills Carbon JV) to assist with our share of the funding obligation. OGCI contributed approximately $2 million to the Elk Hills Carbon JV in the first quarter of 2020 and the cost-sharing payment was made to EPRI during the second quarter of 2020. We are currently evaluating the results of the FEED scope and study. The amounts related to our Elk Hills Carbon JV are not significant to our condensed consolidated financial statements for all periods presented.

The following is a summary of a consolidated joint venture arrangement which was terminated in October 2020 in connection with our emergence from bankruptcy:

Ares JV

In February 2018, our wholly-owned subsidiary California Resources Elk Hills, LLC entered into a midstream joint venture with ECR Corporate Holdings, L.P. (ECR), a portfolio company of Ares, with respect to the Elk Hills power plant and a cryogenic gas processing plant (Ares JV). These assets were held by the joint venture entity, Elk Hills Power, LLC (Elk Hills Power). We held 50% of the Class A common interest and 95.25% of the Class C common interest in Elk Hills Power and ECR held 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. As described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report, upon our emergence from bankruptcy, we acquired all of the equity interests held by ECR in exchange for EHP Notes, 20.8% (subject to dilution) of our common stock and approximately $2 million in cash.

Our condensed consolidated statements of operations for the three months ended March 31, 2020 reflect the operations of the Ares JV, with ECR's share of net income (loss) reported in net income attributable to noncontrolling interests. Distributions to our former joint venture partner are reported as financing cash outflows on our condensed consolidated statement of cash flows for the period ended March 31, 2020.

Other

For more information on our other joint ventures that are unconsolidated joint ventures, including the Alpine JV, the JV with Macquarie Infrastructure and Real Assets Inc., and the JV with Royale Energy, Inc., please see Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our 2020 Annual Report.

NOTE 7 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We, or certain of our subsidiaries, are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at March 31, 2021 and December 31, 2020 were not material to our condensed consolidated balance sheets as of such dates.

In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with an approximately 35% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. We are currently evaluating this claim.

We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.

NOTE 8 DERIVATIVES

We maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. We did not have any derivative instruments designated as accounting hedges as of and during the three months ended March 31, 2021 and 2020. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as accounting hedges.

Our Revolving Credit Facility requires that we hedge a significant amount of crude oil production for a period of 36 months from the effective date of the facility. In addition, the Revolving Credit Facility requires that we maintain hedges on production for not less than two years from each quarter end.

Summary of open derivative contracts — We held the following Brent-based crude oil contracts as of March 31, 2021:


	Q2 2021		Q3 2021		Q4 2021		2022		January - October 2023
Sold Calls
Barrels per day	33,537		36,362		36,700		30,783		17,758
Weighted-average price per barrel	$	48.73	$	50.31	$	60.70	$	59.37	$	58.01





Purchased Puts
Barrels per day	37,872		36,617		35,483		30,783		17,758
Weighted-average price per barrel	$	40.00	$	40.00	$	40.00	$	40.00	$	40.00

Sold Puts
Barrels per day	15,149		14,647		14,193		3,042		—
Weighted-average price per barrel	$	31.41	$	30.00	$	32.00	$	32.00	$	—

Swaps
Barrels per day	9,639		10,063		10,922		7,069		5,919
Weighted-average price per barrel	$	46.35	$	49.09	$	51.11	$	47.34	$	47.57

The outcomes of the derivative positions are as follows:

•Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.

•Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.

•Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.

•Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.

We use combinations of these positions to meet the requirements of our Revolving Credit Facility and to increase the efficacy of our hedging program.

Fair value of derivatives — The following tables present the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of March 31, 2021 and December 31, 2020:


March 31, 2021 (Successor)
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets	$	12	$	(12)	$	—
Other assets	38		(38)		—

Liabilities
Accrued liabilities	(163)		12		(151)
Other long-term liabilities	(124)		38		(86)
	$	(237)	$	—	$	(237)


December 31, 2020 (Successor)
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets, net	$	21	$	(21)	$	—
Other assets	63		(63)		—

Liabilities
Accrued liabilities	(71)		21		(50)
Other long-term liabilities	(69)		63		(6)
	$	(56)	$	—	$	(56)

Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented. We recognized fair value changes on derivative instruments each reporting period in net derivative (loss) gain from commodity contracts on our condensed consolidated statements of operations for the three months ended March 31, 2021 and 2020. The changes in fair value result from the relationship between our existing positions, volatility, time to expiration, contract prices and the associated forward curves.

Fair value of interest rate contracts — At March 31, 2021, we held derivative contracts that limited our interest-rate exposure with respect to a notional amount of $1.3 billion of variable-rate indebtedness. The fair value of our interest-rate derivative contracts was not significant for all periods presented and these contracts expired on May 4, 2021.

NOTE 9 EARNINGS PER SHARE

We compute basic and diluted earnings per share (EPS) using the treasury stock method for the three months ended March 31, 2021 and the two-class method for the three months ended March 31, 2020 which is required for participating securities. Certain of our restricted and performance stock unit awards outstanding during the Predecessor period were considered participating securities because they had non-forfeitable dividend rights at the same rate as our pre-emergence common stock. Our restricted and performance stock unit awards granted in the first quarter of 2021, as described in Note 15 Stock-Based Compensation, are not considered participating securities since the dividend rights on unvested shares are forfeitable.

Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net income attributable to common stock in determining net income available to common stockholders. In loss periods, no allocation is made to participating securities because participating securities do not share in losses. For basic EPS, the weighted-average number of common shares outstanding excludes underlying shares related to unvested equity-settled awards and warrants. For diluted EPS, the basic shares outstanding are adjusted by adding potential common shares, if dilutive.

The following table presents the calculation of basic and diluted EPS, for the three months ended March 31, 2021 and 2020:


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions, except per-share amounts)
Numerator for Basic and Diluted Earnings per Share
Net loss	$	(89)	$	(1,745)
Less: net income attributable to noncontrolling interests	(5)		(51)
Net loss attributable to common stock	$	(94)	$	(1,796)

Denominator for Basic and Diluted Earnings per Share
Weighted-average shares	83.3		49.3







Earnings per Share
Basic	$	(1.13)	$	(36.43)
Diluted	$	(1.13)	$	(36.43)

Weighted-average anti-dilutive shares	5.4		4.6

NOTE 10 PENSION AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three months ended March 31, 2021 and 2020:


	Successor				Predecessor
	Three months ended March 31,				Three months ended March 31,
	2021				2020
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
(in millions)
Service cost	$	—	$	1	$	—	$	1
Interest cost	—		1		1		1



Total	$	—	$	2	$	1	$	2

We did not make significant contributions to our defined benefit plans for the three months ended March 31, 2021. We expect to satisfy minimum funding requirements with contributions of approximately $3 million to our defined benefit pension plans during the remainder of 2021.

We did not make significant contributions to our defined benefit pension plans for the three months ended March 31, 2020. The Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted on March 27, 2020 and allowed for the deferral of contributions to a single employer pension plan otherwise due during 2020 to January 1, 2021. We deferred contributions to our defined benefit pension plans of approximately $5 million during 2020, which we paid in December 2020.

NOTE 11 REVENUE RECOGNITION

We derive most of our revenue from sales of oil, natural gas and NGLs, with the remaining revenue primarily generated from sales of electricity and marketing activities related to storage and managing excess pipeline capacity.

The following table provides disaggregated revenue for sales for oil, natural gas and NGLs to customers:


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
Oil, natural gas and NGL sales:
Oil	$	331	$	356
Natural gas	47		38
NGLs	54		36
	$	432	$	430

NOTE 12 LEASES

Balance sheet information related to our operating and finance leases was as follows:


		Successor
	Classification	March 31, 2021		December 31, 2020
		(in millions)
Assets
Operating	Other assets	$	39	$	38
Finance	PP&E	1		1
Total leased assets		$	40	$	39

Liabilities
Current
Operating	Accrued liabilities	$	9	$	6
Finance	Accrued liabilities	1		1
Long-term
Operating	Other long-term liabilities	34		35
Finance	Other long-term liabilities	—		—
Total lease liabilities		$	44	$	42

Our operating lease assets and liabilities increased from year end 2020 primarily due to adding one drilling rig in the first quarter of 2021.

NOTE 13 INCOME TAXES

We estimate our annual effective income tax rate to record our quarterly income tax provision in the jurisdictions in which we operate. Statutory tax rate changes and other significant or unusual items, if any, are not included in our annual effective income tax rate and are instead recognized as discrete items in the quarter in which they occur.

For the three months ended March 31, 2021 and 2020, we did not provide any current or deferred income tax provision or benefit. The difference between our statutory tax rate and our effective tax rate of zero for all periods presented includes changes to maintain our full valuation allowance against our net deferred tax assets given our recent and anticipated future earnings trends. We believe that there is a reasonable possibility that some or all of this allowance could be released in the foreseeable future. However, the amount of the net deferred tax assets considered realizable depends on the sustained level of profitability that we can achieve.

NOTE 14 ASSET IMPAIRMENTS

The following table presents a summary of our asset impairments:


	Successor		Predecessor
	March 31, 2021		March 31, 2020
(in millions)
Proved oil and natural gas properties	$	—	$	1,487
Unproved properties	—		228
Other	3		21
Total	$	3	$	1,736

At March 31, 2021, we recorded a $3 million impairment which was triggered by the change in our business strategy and capital allocation priorities resulting in the impairment of capitalized costs related to projects which were abandoned.

At March 31, 2020, we recorded a $1.7 billion impairment which was triggered by the sharp drop in commodity prices at the end of the first quarter of 2020 due to the significant decrease in demand for oil and natural gas products as a result of the Coronavirus Disease 2019 (COVID-19) pandemic coupled with the over-supply resulting from a price war between members of the Organization of the Petroleum Exporting Countries (OPEC), Russia and other allied producing countries. Other asset impairments recorded in the three months ended March 31, 2020 primarily included the write-off of amounts due from joint interest partners which were recoverable solely from our partners’ share of future production from associated fields. The dramatic commodity price decline during the first quarter of 2020 resulted in changes to our cash flow forecasts and we impaired the carrying value of these amounts. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 13 Asset Impairment in our 2020 Annual Report for a description of our impairment of proved and unproved oil and gas properties as of March 31, 2020.

NOTE 15 STOCK-BASED COMPENSATION

As a result of our bankruptcy, our Amended and Restated California Resources Corporation Long-Term Incentive Plan was cancelled and, upon emergence, all outstanding stock-based compensation awards granted under this plan were cancelled.

On January 18, 2021, our Board of Directors approved the California Resources Corporation 2021 Long Term Incentive Plan (2021 Incentive Plan) and as a result, the 2021 Incentive Plan became effective. The 2021 Incentive Plan provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-based awards and substitute awards to employees, officers, non-employee directors and other service providers of the Company and its affiliates. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 14 Stock-Based Compensation in our 2020 Annual Report for additional information including the number of shares authorized for awards.

Shares of our common stock may be withheld by us in satisfaction of tax withholding obligations arising upon the vesting of restricted stock and performance stock units.

Stock-based compensation expense is recorded as a component of operating costs and general and administrative expenses on our condensed consolidated statements of operations as follows:


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
General and administrative expenses	$	2	$	1
Operating costs	—		(1)
Total stock-based compensation expense	$	2	$	—

For the three months ended March 31, 2021 and 2020, we did not recognize any income tax benefit related to our stock-based compensation. For the three months ended March 31, 2020, we made cash payments of $8 million for the cash-settled portion of our pre-emergence awards.

Restricted Stock Units

In the first quarter of 2021, we granted restricted stock units (RSUs) to our non-employee directors and certain of our executives. The awards generally vest ratably over three years, with one third of the granted units vesting on each of the first three anniversaries of the applicable date of grant. RSUs are settled in shares of our common stock at the end of the three-year vesting period.

Compensation expense was measured on the date of grant using the quoted market price of our common stock and is recognized on a straight-line basis over the requisite service periods adjusted for actual forfeitures, if any.

As of March 31, 2021, the unrecognized compensation expense for all of our unvested RSUs was approximately $25 million and is expected to be recognized over a weighted-average period of three years.



	Number of Units	Weighted-Average Grant-Date Fair Value
	(in thousands)

Granted	1,057	$	24.45
Cancelled or Forfeited	(9)	$	24.50
Unvested at March 31, 2021 (Successor)	1,048

Performance Stock Units

In the first quarter of 2021, we granted certain of our executives performance stock units (PSUs). PSUs are earned upon the attainment of specified 60-trading day volume weighted average prices for shares of our common stock during a three-year service period commencing on the grant date. Once units are earned, the earned units are not reduced for subsequent decreases in stock price. For the duration of the three-year period, a minimum of 0% and a maximum of 100% of the PSUs granted could be earned. Earned PSUs vest on the third anniversary of the grant date and are settled in shares of our common stock at that time.



	Number of Units	Weighted-Average Grant-Date Fair Value
	(in thousands)

Granted	869	$	19.47
Cancelled or Forfeited	(9)	$	19.31
Unvested at March 31, 2021 (Successor)	860

The grant date fair value and associated equity compensation expense was measured using a Monte Carlo simulation model which runs a probabilistic assessment of the number of units that will be earned based on a projection of our stock price during the three-year service period.

The range of assumptions used in the Monte Carlo simulation model for the PSUs granted during the first quarter of 2021 were as follows:





Expected volatility(a)	65.00	%
Risk-free interest rate(b)	0.17% - 0.32%
Dividend yield	—	%
Forecast period (in years)	3

(a)Expected volatility was calculated using a peer group due to our limited trading history since our emergence from bankruptcy.

(b)Based on the U.S. Treasury yield for a three-year term at the grant date.

Compensation expense is recognized on a straight-line basis over the requisite service periods adjusted for actual forfeitures, if any.

As of March 31, 2021, the unrecognized compensation expense for all of our unvested PSUs was approximately $16 million and is expected to be recognized over a weighted-average period of three years.

NOTE 16 SUBSEQUENT EVENTS

In May 2021, our Board of Directors authorized a Share Repurchase Program (SRP) to acquire up to $150 million of our common stock through March 31, 2022. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The SRP does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time.

Refer to Note 5 Debt for a description of lender commitments in April 2021 and a May 2021 amendment to our Revolving Credit Facility which provides flexibility on hedging requirements and increased our capacity to make certain restricted payments.

Item 2Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

Chapter 11 Proceedings

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases). On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new equity owners and a significantly improved financial position.

Fresh Start Accounting

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 3 Fresh Start Accounting in our Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report) for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

Organization Changes

In January 2021, we reduced the size of our management team and then realigned several functions in February 2021, which resulted in additional headcount and cost reductions, making progress towards our lower cost operating model. We changed our 2021 capital guidance to reallocate investments to downhole maintenance activities, which will result in an increase in estimated 2021 operating costs. As a result, we expect our sustainable cost savings in general and administrative expense and operating costs to be $80 million in 2021 as compared to 2020 levels. We believe the steps taken to date have improved our financial condition and streamlined our business.

In connection with our emergence from bankruptcy, our Board of Directors was reconstituted in October 2020. On December 31, 2020, our former President, Chief Executive Officer and director Todd A. Stevens departed and Mark A. (Mac) McFarland was appointed as interim Chief Executive Officer in addition to his role as Chair of our Board of Directors. On March 22, 2021, the Board of Directors appointed Mr. McFarland as President and Chief Executive Officer on a permanent basis. On April 15, 2021, Tiffany (TJ) Thom Cepak replaced Mr. McFarland as the Chair of our Board of Directors. Mr. McFarland will continue to serve as a director.

Recent Debt Transactions

In January 2021, we completed a private offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $588 million, after $12 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and our EHP Notes, with the remaining proceeds used to pay down a portion of the outstanding borrowings under our Revolving Credit Facility. For more information on the terms of Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 5 Debt.

In May 2021, we amended the Revolving Credit Facility to:

•increase our borrowing base from $1.167 billion to $1.2 billion;

•evidence the reduction in the aggregate commitment of lenders from $540 million to $492 million;

•increase our capacity to make certain restricted payments;

Share Repurchase Program

Business Environment and Industry Outlook

Commodity Prices

Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.

Global oil prices gradually increased beginning in October 2020 through the first quarter of 2021. Benchmark prices for Brent crude oil in the first quarter of 2021 increased approximately 35% from the fourth quarter of 2020 demonstrating a strong recovery from the prior year when oil prices were negatively influenced by the Coronavirus Disease 2019 (COVID-19) pandemic. Current pricing has benefited from the gradual re-opening of the economy and the lifting of restrictions related to the COVID-19 pandemic. Further, members of Organization of Petroleum Exporting Countries (OPEC) and non-OPEC producers have restrained crude oil production attempting to reduce oil supplies built during the worst period of the pandemic.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2021, December 31, 2020 and March 31, 2020:



	Three months ended March 31,		Three months ended December 31,		Three months ended March 31,
	2021		2020		2020
Brent oil ($/Bbl)	$	61.10	$	45.24	$	50.96
WTI oil ($/Bbl)	$	57.84	$	42.66	$	46.17
NYMEX gas ($/MMBtu)	$	2.72	$	2.66	$	2.05

Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units.

See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production and Prices and Part II, Item 1A – Risk Factors in our 2020 Annual Report for further discussion regarding the impact of the pandemic and declines in commodity prices.

Recent Developments

Certain actions of the new U.S. administration could impact the oil and gas industry. Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production. Such outcomes could materially and adversely affect our business, results of operations and financial condition.

On April 23, 2021, Governor Gavin Newsom signed an executive order directing the California Department of Conservation’s Geologic Energy Management Division to initiate a rulemaking to end the issuance of new permits for well stimulation treatments by January 1, 2024 and instructed the California Air Resources Board to evaluate methods of phasing out oil extraction across the state by 2045. This marks a reversal from the governor’s previous statements that he lacked the executive authority to ban hydraulic fracturing, and any decision to prohibit the extraction of oil would likely be subject to significant opposition and legal challenge. Regardless of whether or not such a ban is upheld, we expect little to no impact on future development activities because we are not dependent on well stimulation treatments. Less than 1% of our proved reserves require well stimulation and our current long-term development plans do not include well stimulation.

Operations

We have the largest privately held oil and natural gas mineral acreage position in California, consisting of 2.1 million net mineral acres spanning four of California's major oil and natural gas basins. We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. Approximately 65% of our mineral acreage is held in fee and the remainder is leased. Of our leased acreage, approximately 50% is held by production and the remainder is subject to lease expiration if initial producing wells are not drilled within a specified period of time. The primary terms of our leases range from one to ten years. The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained.

As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells in response to a low commodity price environment while retaining our oil and gas leases which are held by production. With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities.

We also own or control a network of integrated infrastructure that complements our operations including gas processing plants, oil and gas gathering systems, power plants and other related assets. Our strategically located infrastructure helps us maximize the value generated from our production. Beyond our essential role in supplying Californians with oil, natural gas, NGLs and electricity, our 2030 Sustainability Goal for carbon is to design and permit California’s first carbon capture and sequestration system by mid-decade which is expected to reduce carbon emissions associated with our operations and significantly extend the productive life of our Elk Hills field.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 16% of our net production for the three months ended March 31, 2021.

In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our oil, natural gas and NGL sales revenue, general and administrative expenses and operating costs but has no effect on our net results.

Marketing Arrangements

We own a large and geographically diverse portfolio of assets that generate the following revenue streams:

Crude Oil — We sell almost all of our crude oil into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S. regions. Substantially all of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong. California is heavily reliant on imported sources of energy, with approximately 70% of oil and 90% of natural gas consumed in 2019 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades.

Natural Gas — We sell all of our natural gas not used in our operations into the California markets on a daily basis at average monthly index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity in the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada. As a result, we typically enjoy higher netback pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and approximately 11% of our revenue from oil, natural gas and NGL sales are from natural gas.

In addition to selling our produced natural gas, we also purchase natural gas for use in steam generation for our steamfloods and power generation. The positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to more volumes sold than used. Conversely, lower natural gas prices lower our operating costs but have a net negative effect on our financial results.

We currently have transportation capacity contracts to transport the majority of our natural gas volumes until September 2023.

Natural Gas Liquid (NGL) — NGL price realizations are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints and seasonality can magnify price volatility.

Our earnings are also affected by the performance of our complementary natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a pipeline delivery contract to transport 6,500 barrels per day of NGLs to market through March 2023. Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped. We have thus far met all of our shipping commitments under this contract. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 30% of our NGLs are sold to export markets.

Electricity — Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces field operating costs and provides a reliable source of power. We sell the excess electricity generated to a local utility, other third parties and the grid. The power sold to the utility is subject to an agreement through the end of 2023, which includes a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Any excess capacity not sold to other third parties is sold to the wholesale power market. The prices obtained for excess power impact our earnings but generally by a relatively small amount.

Hedging

Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows.

Our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred on the Effective Date, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.

We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report if our leverage ratio is greater than 2.00:1.00. If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are required to maintain is reduced from 50% to 33%. Currently, we may not hedge more than 85% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period.

In the three months ended March 31, 2021, we added hedges on one million barrels of production for the period from April 2021 to March 2022 at a weighted-average Brent price of approximately $61 per barrel. See Liquidity and Capital Resources below for a current table summarizing our outstanding derivative contracts.

Seasonality

While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a material driver of changes in our quarterly results.

Fixed and Variable Costs

Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. The measures taken to address the industry downturn in the prior year demonstrate that we can significantly reduce our operating costs in response to prevailing market conditions. We further believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs in a safe and responsible manner throughout their lifecycles.

Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2021 and 2020:


	Successor	Predecessor
	Three months ended March 31,	Three months ended March 31,
	2021	2020
Oil (MBbl/d)
San Joaquin Basin	38	47
Los Angeles Basin	20	26
Ventura Basin	2	4

Total	60	77
NGLs (MBbl/d)
San Joaquin Basin	12	14

Ventura Basin	—	—

Total	12	14
Natural gas (MMcf/d)
San Joaquin Basin	135	152
Los Angeles Basin	1	2
Ventura Basin	4	6
Sacramento Basin	20	23
Total	160	183

Total Net Production (MBoe/d)	99	121

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.

For the three months ended March 31, 2021 compared to the same period in 2020, total daily production decreased by approximately 22 MBoe/d or 18%. The decrease in production largely resulted from limited drilling and capital investment during the prior 12 months. Our average drilling rigs decreased from 7 in the three months ended March 31, 2020 to 1 rig in the three months ended March 31, 2021. In addition, production was also negatively impacted by 1 MBoe/d in the first quarter of 2021 compared to 2020 due to downtime at one of our gas processing plants. Our PSC-type contracts negatively impacted our oil production in the first quarter of 2021 by approximately 3 MBoe/d compared to the same period in 2020. Our total daily production decreased by approximately 15% compared to the same period in 2020 after excluding the impact of PSC-type contracts and unscheduled downtime at one of our natural gas processing plants.

The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three months ended March 31, 2021 and 2020:


	Successor			Predecessor
	Three months ended March 31,			Three months ended March 31,
	2021			2020
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	61.10		$	50.96

Realized price without hedge	$	60.81	100%	$	50.78	100%
Settled hedges	(7.08)			4.72
Realized price with hedge	$	53.73	88%	$	55.50	109%

WTI	$	57.84		$	46.17
Realized price without hedge	$	60.81	105%	$	50.78	110%
Realized price with hedge	$	53.73	93%	$	55.50	120%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	48.77	80%	$	29.28	57%
Realized price (% of WTI)	$	48.77	84%	$	29.28	63%

Natural gas
NYMEX ($/MMBtu)	$	2.72		$	2.05

Realized price without hedge ($/Mcf)	$	3.29	121%	$	2.25	110%
Settled hedges	(0.04)			0.10
Realized price with hedge ($/Mcf)	$	3.25	119%	$	2.35	115%

Oil — Brent index and realized prices without hedge settlements were higher in the three months ended March 31, 2021 compared to the same prior-year period due to a recovery in oil demand from the severe demand decline caused by COVID-19 in 2020. Prices collapsed in March 2020 at the beginning of the pandemic and have since improved as a result of easing restrictions and the significant production curtailments by OPEC members and Russia. Further, most producers in other nations also curtailed production and significantly reduced their capital investments in response to COVID-19 in 2020, which continued into 2021.

NGLs — Prices for NGLs increased for the three months ended March 31, 2021 compared to the same period in 2020 as supply in 2020 outpaced demand, causing lower NGL prices in the first quarter of 2020. In the first quarter of 2021, producers continued to curtail production and the tighter supply resulted in higher benchmark prices and price realizations as compared to the same prior year period.

Natural Gas — Our natural gas realized prices were higher in the three months ended March 31, 2021 than the comparable period of 2020 due to increased natural gas demand in the nationwide markets. This was a significant change from the first quarter of 2020 in which demand decreased as a result of shelter-in-place orders related to COVID-19.

Statements of Operations Analysis

We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the implementation of the Plan, our results of operations for the Successor period may not be comparable with that of the Predecessor period. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

Results of Oil and Gas Operations

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended March 31, 2021 and 2020:


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
Energy operating costs(a)	$	4.70	$	3.71
Gas processing costs	0.53		0.67
Non-energy operating costs(b)	13.10		13.00
Operating costs	$	18.33	$	17.38

Operating costs, excluding effects of PSC-type contracts(c)	$	16.72	$	16.48
Field general and administrative expenses(d)	$	0.89	$	1.09
Field depreciation, depletion and amortization(d)(e)	$	5.14	$	10.05
Field taxes other than on income(d)	$	3.46	$	3.08

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

(b)Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

(c)As described in the Operations section, 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. These amounts represent our operating costs after adjusting for this difference.

(d)Excludes corporate expenses.

(e)Field depreciation, depletion and amortization decreased in the three months ended March 31, 2021 from the same period in 2020 primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the fresh start valuation of our property, plant and equipment.

Consolidated Results of Operations

The following table presents our consolidated results of operations and key financial measures for the three months ended March 31, 2021 and 2020:


	Successor		Predecessor
	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
Oil, natural gas and NGL sales	$	432	$	430
Net derivative (loss) gain from commodity contracts	(213)		79
Trading revenue	98		45
Electricity sales	33		13
Other revenue	13		6
Operating costs	(164)		(192)
General and administrative expenses	(48)		(60)
Depreciation, depletion and amortization	(52)		(119)
Asset impairments	(3)		(1,736)
Taxes other than on income	(40)		(41)
Exploration expense	(2)		(5)
Trading costs	(61)		(24)
Electricity cost of sales	(24)		(16)
Transportation costs	(12)		(13)
Other expenses, net	(30)		(16)
Reorganization items	(2)		—
Interest and debt expense, net	(13)		(87)
Net gain on early extinguishment of debt	(2)		5
Gain on asset divestitures	2		—
Other non-operating expenses	(1)		(14)
Loss before income taxes	(89)		(1,745)
Income tax	—		—
Net loss	(89)		(1,745)
Net income attributable to noncontrolling interests	(5)		(51)
Net loss attributable to common stock	$	(94)	$	(1,796)

Three months ended March 31, 2021 vs. 2020

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the impact of settled hedges, were $432 million for the three months ended March 31, 2021, which is an increase of $2 million compared to $430 million for the same period of 2020. The increase was due to higher realized prices, which was partially offset by lower production, as reflected in the following table:


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended March 31, 2020	$	356	$	36	$	38	$	430
Changes in realized prices	71		24		18		113
Changes in production	(96)		(6)		(9)		(111)
Three months ended March 31, 2021	$	331	$	54	$	47	$	432

Note: See Production and Prices for index prices, realizations and production volumes for comparative periods.

The effect of settled hedges is not included in the table above. Payments for settled hedges were $39 million for the three months ended March 31, 2021 compared to proceeds of $98 million, including $63 million of proceeds from derivative contracts sold prior to maturity, for the same period of 2020. Including the effect of settled hedges, our oil, natural gas and NGL revenue decreased by $135 million or 26% compared to the same prior-year period.

Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $213 million for the three months ended March 31, 2021 compared to a net gain of $79 million in the same period of 2020. The non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices and the associated forward curves.


	Three months ended March 31,		Three months ended March 31,
	2021		2020
(in millions)
Non-cash derivative (loss), excluding noncontrolling interest	$	(174)	$	(35)
Non-cash derivative gain, noncontrolling interest	—		16
Total non-cash changes	(174)		(19)
Net (payments) proceeds on settled commodity derivatives	(39)		35
Net proceeds on derivative contracts sold prior to maturity	—		63
Net derivative (loss) gain from commodity contracts	$	(213)	$	79

Trading revenue – Trading revenue was $98 million for the three months ended March 31, 2021, an increase of $53 million, or 118% from $45 million during the same period of 2020. The increase was predominantly the result of higher volume and prices related to our natural gas trading activities. Our net profit from natural gas trading activities, after consideration of trading costs described below, was $37 million for the three months ended March 31, 2021 compared to $21 million for the same period of 2020.

Electricity sales – Electricity sales increased $20 million to $33 million in the first quarter of 2021 compared to $13 million in the same period of 2020. There were lower electricity sales in the first quarter of 2020 as a result of planned major maintenance at the Elk Hills power plant.

Operating costs — Operating costs for the three months ended March 31, 2021 were $164 million, which was a decrease of $28 million or 15% from $192 million for the same period of 2020. The decrease was primarily attributable to efficiencies and streamlining of our operations, including headcount reductions in the second half of 2020 and in the first quarter of 2021.

General and administrative expenses — Our general and administrative (G&A) expenses were $48 million for the three months ended March 31, 2021, which was a decrease of $12 million from $60 million for the three months ended March 31, 2020. The decrease in G&A expenses were attributable to efficiencies and streamlining of our operations, including a decrease of $7 million in employee related expenses as a result of workforce reductions.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $67 million to $52 million in the first quarter of 2021 compared to $119 million in the same period of 2020 was primarily due to a decrease in the carrying value of our property, plant and equipment as a result of fair value adjustments recorded as part of fresh start accounting. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting in our 2020 Annual Report for additional information on the valuation of our property, plant and equipment.

Asset impairments – Asset impairment charges for the three months ended March 31, 2021 were $3 million for the impairment of capitalized costs related to projects which were abandoned. For the same period in 2020, we recorded an impairment charge of $1.7 billion due to the sharp drop in commodity prices in March 2020, which included $1.5 billion related to certain of our proved properties and approximately $228 million related to unproved acreage that was no longer included in our development plans at that time. See Part I, Item 1 – Financial Statements, Note 14 Asset Impairments for additional information.

Trading costs – Natural gas purchases related to trading activities were $61 million for the three months ended March 31, 2021, which was an increase of $37 million or 154% from $24 million for the same period in 2020. The change was predominantly the result of higher activity levels and prices related to natural gas trading activities.

Other expenses, net – Other expenses, net was $30 million for the three months ended March 31, 2021, which was an increase of $14 million from $16 million during the same period of 2020. The increase was largely the result of a restructuring charge related to workforce reductions in the three months ended March 31, 2021.

Interest and debt expense, net — Interest and debt expense, net decreased $74 million to $13 million in the first quarter of 2021 compared to $87 million in the same period of 2020 primarily due to a decrease in our overall level of debt upon our emergence from bankruptcy. Additionally, in the first quarter of 2021, we reduced the amount drawn on our Revolving Credit Facility and had no balance drawn for two months in the period. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings and Note 8 Debt in our 2020 Annual Report for additional information on the terms of the Plan, our emergence from bankruptcy and our long-term debt transactions.

Other non-operating expense — Other non-operating expense decreased $13 million to $1 million for the three months ended March 31, 2021 compared to $14 million in the same period for 2020. The expense in the first quarter of 2020 was primarily a result of legal, professional and other fees associated with the preparation of the Chapter 11 Cases, which were incurred prior to our petition date, and abandoned transactions.

Net income attributable to noncontrolling interests — Upon emergence from bankruptcy, we acquired all of

ECR's member interests in the Ares JV; therefore, the allocation of net income to noncontrolling interest

holders in the Successor period for the three months ended March 31, 2021 is lower than the Predecessor period for the three months ended March 31, 2020. See Part I, Item 1 – Financial Statements, Note 7 Joint Ventures for additional information on the settlement terms of the Ares JV.

Liquidity and Capital Resources

Cash Flow Analysis

Cash flows from operating activities — Our net cash provided by operating activities is sensitive to many variables, including changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. Our operating cash flow decreased 36%, or $81 million, to $147 million for the three months ended March 31, 2021 from $228 million in the same period of 2020. The net change in operating cash flow includes decreases primarily from: (i) settlement payments on our derivative contracts in the first quarter of 2021 compared to proceeds received during the first quarter of 2020 and (ii) a large increase in trade accounts receivable resulting from changes in entry and exit prices between the comparative quarters. These decreases were partially offset by lower (i) operating costs primarily related to workforce reductions, (ii) interest payments on our long-term debt and (iii) payments of variable compensation as a result of changing from an annual payment in the first quarter of 2020 compared to quarterly payments in the first quarter of 2021.

Cash flows from investing activities — Our net cash used in investing activities increased $8 million, or 67% from $12 million for the three months ended March 31, 2020 to $20 million for the same period in 2021. Cash used in investing activities included $49 million for capital investment in the three months ended March 31, 2020 compared to $22 million in the three months ended March 31, 2021 due to lower activity levels in 2021. Capital investments were partially offset by $41 million related to royalty interest and non-core asset sales in the first quarter of 2020 as compared to proceeds of $2 million in the first quarter of 2021 for non-core asset sales.

The table below summarizes net cash used in investing activities for the three months ended March 31, 2021 and 2020 (in millions):


	Successor		Predecessor
	Three months ended March 31, 2021		Three months ended March 31, 2020
(in millions)
Capital investments	$	(27)	$	(30)
Changes in capital investment accruals	5		(19)
Proceeds from divestitures	2		41
Other	—		(4)
Net cash used in investing activities	$	(20)	$	(12)

Cash flows from financing activities — Our net cash used in financing activities of $25 million for the three months ended March 31, 2021 included $14 million of distributions to noncontrolling interest holders and a net $11 million of cash used to repay long-term debt. See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our debt.

Our net cash used in financing activities for the three months ended March 31, 2020 was $156 million and primarily included net repayments of $110 million on our debt obligations and $42 million in net distributions to noncontrolling interest holders. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report for a description of our Second Lien Notes.

The table below summarizes net cash used by financing activities for the three months ended March 31, 2021 and 2020 (in millions):


	Successor		Predecessor
	Three months ended March 31, 2021		Three months ended March 31, 2020
(in millions)
Debt transactions, net	$	(11)	$	(110)
Debt repurchases	—		(3)
Distributions to noncontrolling interest holders, net	(14)		(42)

Other	—		(1)
Net cash used by financing activities	$	(25)	$	(156)

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand and available borrowing capacity under our Revolving Credit Facility. We emerged from bankruptcy with a strong balance sheet and low leverage. We have substantially revamped our cost structure while maintaining sustainable operations. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining.

At current commodity prices and our planned 2021 capital program described below, we expect to generate positive free cash flow, which may be used to (i) increase investments in our drilling program to accelerate value, (ii) pay dividends or buy back stock to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, or (iii) maintain cash on our balance sheet. We may be required to begin paying income taxes if Brent prices remain above $60 per barrel for a sustained period. Our tax paying status depends on a number of factors, including but not limited to, potential legislation which could limit tax incentives for fossil fuels, the amount and type of our capital spend, cost structure and activity levels. We believe we have sufficient sources of cash to meet our obligations for the next twelve months. Based on the timing of our anticipated cash distributions to Benefit Street Partners (BSP) at current commodity prices, we believe the preferred interest held by BSP in our development joint venture could be automatically redeemed early in the fourth quarter of 2021. See Part I, Item 1 – Financial Statements, Note 6 Joint Ventures for additional information on our BSP JV.

The following table summarizes our liquidity (in millions):


	Successor
	March 31,		April 30,
	2021		2021
	(in millions)
Unrestricted cash	$	130	$	123
Revolving Credit Facility:
Borrowing capacity(a)	540		492
Letters of credit outstanding	(125)		(125)
Total availability	$	415	$	367

Liquidity	$	545	$	490

(a)In April 2021, the aggregate commitment of our lenders was reduced to $492 million based on the terms of our Revolving Credit Facility. See Part I, Item 1 – Financial Statements, Note 5 Debt for more information on our Revolving Credit Facility.

Derivatives

Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. To mitigate some of the risk inherent in the downward movement in oil prices, we may enter into various derivative instruments to hedge commodity price risk.

Commodity Contracts

Our Revolving Credit Facility requires us to maintain hedges on a notional amount of crude oil production as described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt in our 2020 Annual Report. Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2021.

At April 30, 2021, we had the following Brent-based crude oil contracts:


	Q2 2021		Q3 2021		Q4 2021		1H 2022		2H 2022		January - October 2023
Sold Calls
Barrels per day	33,537		36,688		37,037		33,842		27,773		17,758
Weighted-average price per barrel	$	48.73	$	50.47	$	60.75	$	60.00	$	58.62	$	58.01





Purchased Puts
Barrels per day	37,872		36,943		35,820		33,842		27,773		17,758
Weighted-average price per barrel	$	40.00	$	40.18	$	40.19	$	40.00	$	40.00	$	40.00

Sold Puts
Barrels per day	15,149		14,647		14,193		3,416		2,674		—
Weighted-average price per barrel	$	31.41	$	30.00	$	32.00	$	32.00	$	32.00	$	—

Swaps
Barrels per day	9,639		10,063		10,922		7,763		6,386		5,919
Weighted-average price per barrel	$	46.35	$	49.09	$	51.11	$	48.17	$	46.34	$	47.57

The outcomes of the derivative positions are as follows:

•Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.

•Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.

•Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.

2021 Capital Program

Our capital program will be dynamic in response to oil market volatility while focusing on maintaining our oil production and strong liquidity and maximizing our free cash flow. We entered 2021 with an internally funded capital program of $200 million to $225 million. During the first quarter of 2021, the 2021 capital program was revised to $185 million to $210 million reflecting a reallocation of drilling capital to downhole maintenance, which provide efficiencies and faster payouts. Our current plan anticipates we will gradually raise quarterly capital investment throughout the year.

If commodity prices decline significantly from current levels, we may need to adjust our capital program in response to market conditions. Any curtailment of the development of our properties will lead to a decline in our production and may lower our reserves. A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets.

The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals (in millions):


	2021 Target	Three months ended March 31, 2021
	(in millions)
Drilling	$105 - $120	$	13
Capital workovers	35 - 40	7
Infrastructure, corporate and other	45 - 50	7
Total	$185 - $210	$	27

Lawsuits, Claims, Commitments and Contingencies

We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

Significant Accounting and Disclosure Changes

See Part I, Item 1 – Financial Statements, Note 2 Accounting and Disclosure Changes for a discussion of new accounting matters.

Forward-Looking Statements

The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our 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 we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite 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:

•our ability to execute our 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 our recent emergence from bankruptcy on our business and relationships;

•debt limitations on our financial flexibility;

•insufficient cash flow to fund planned investments, interest payments on our debt, debt repurchases or changes to our 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;

•our ability to utilize our net operating loss carryforwards to reduce our 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 our products;

•joint ventures and acquisitions and our 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 our 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; and

•factors discussed in Item 1A, Risk Factors in our 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.

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, 2021, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the 2020 Annual Report.

Item 4 Controls and Procedures

Our Chief Executive Officer and our Chief Financial Officer supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2021.

There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended March 31, 2021 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 7 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our 2020 Annual Report.

Item 1A Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading Risk Factors in our 2020 Annual Report. There were no material changes to those risk factors during the three months ended March 31, 2021.

Item 5 Other Disclosures

None.

Item 6 Exhibits


3.1			Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

3.2			Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

4.1			Indenture, dated January 20, 2021, by and among California Resources Corporation, the guarantors and Wilmington Trust, National Association (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 21, 2021 and incorporated herein by reference).

4.2			First Supplemental Indenture, dated January 20, 2021, by and among California Resources Corporation, the guarantors, Elk Hills Power, LLC, EHP Midco Holding Company, LLC, EHP Topco Holding Company, LLC and Wilmington Trust, National Association (filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 21, 2021 and incorporated herein by reference).

10.1			California Resources Corporation 2021 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed January 22, 2021 and incorporated herein by reference).

10.2			Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award for Non-Employee Directors Grant Agreement (filed as Exhibit 10.45 to the Registrant’s Annual Report on Form 10-K filed March 11, 2021 and incorporated herein by reference).

10.3			Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Term and Conditions (filed as Exhibit 10.46 to the Registrant’s Annual Report on Form 10-K filed March 11, 2021 and incorporated herein by reference).

10.4			Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Term and Conditions (filed as Exhibit 10.47 to the Registrant’s Annual Report on Form 10-K filed March 11, 2021 and incorporated herein by reference).

10.5			Form of California Resources Corporation 2021 Long Term Incentive Plan Performance Stock Unit Award Term and Conditions (filed as Exhibit 10.48 to the Registrant’s Annual Report on Form 10-K filed March 11, 2021 and incorporated herein by reference).

10.6			Employment Agreement by and between Mark A. McFarland and California Resources Corporation, dated March 22, 2021 (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed March 22, 2021 and incorporated herein by reference).

10.7			First Amendment to the Credit Agreement, dated as of May 7, 2021, by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as Administrative Agent, Collateral Agent and an Issuing Bank (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed May 10, 2021 and incorporated herein by reference.)

31.1*			Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*			Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*			Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

101.CAL*			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*			Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document.

104			Cover Page Interactive Data File (formatted in inline XBRL and contained in Exhibits 101).

* - Filed herewith

SIGNATURES

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 thereunto duly authorized.


			CALIFORNIA RESOURCES CORPORATION


DATE:	May 13, 2021	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Vice President and Controller
		(Principal Accounting Officer)