California Resources Corp - Quarter Report: 2020 June (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 June 30, 2020

☐ 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	CRCQQ*	N/A*

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


Shares of common stock outstanding as of June 30, 2020			49,453,297

* On July 16, 2020, CRC's common stock trading under the symbol "CRC" was delisted from the New York Stock Exchange (NYSE). Effective July 17, 2020, CRC’s common stock was quoted on the OTC Pink Market under the symbol “CRCQQ”. The delisting of the common stock from the NYSE under Section 12(b) of the Securities Exchange Act of 1934 (Exchange Act) will be effective at the opening of business on August 11, 2020. Upon deregistration of the common stock under Section 12(b) of the Exchange Act, the common stock will remain registered under Section 12(g) of the Exchange Act.

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	7
	Notes to the Condensed Consolidated Financial Statements	8
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
	General	26
	Business Environment and Industry Outlook	26
	Operations	29
	Development Joint Ventures	31
	Fixed and Variable Costs	32
	Production and Prices	33
	Balance Sheet Analysis	35
	Statements of Operations Analysis	36
	Liquidity and Capital Resources	43
	2020 Capital Program	47
	Seasonality	47
	Lawsuits, Claims, Commitments and Contingencies	47
	Significant Accounting and Disclosure Changes	48
	Forward-Looking Statements	49
Item 3	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4	Controls and Procedures	52

Part II
Item 1	Legal Proceedings	53
Item 1A	Risk Factors	53
Item 5	Other Disclosures	59
Item 6	Exhibits	60

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of June 30, 2020 and December 31, 2019

(in millions, except share data)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash	$	126	$	17
Trade receivables	132		277
Inventories	61		67
Other current assets, net	84		130
Total current assets	403		491
PROPERTY, PLANT AND EQUIPMENT	22,914		22,889
Accumulated depreciation, depletion and amortization	(18,465)		(16,537)
Total property, plant and equipment, net	4,449		6,352
OTHER ASSETS	78		115
TOTAL ASSETS	$	4,930	$	6,958


CURRENT LIABILITIES
Current portion of long-term debt	5,083		100
Current portion of deferred gain and issuance costs, net	125		—
Accounts payable	196		296
Accrued liabilities	355		313
Total current liabilities	5,759		709
LONG-TERM DEBT	—		4,877
DEFERRED GAIN AND ISSUANCE COSTS, NET	—		146
OTHER LONG-TERM LIABILITIES	719		720
MEZZANINE EQUITY
Redeemable noncontrolling interests	828		802
EQUITY
Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at June 30, 2020 and December 31, 2019	—		—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (June 30, 2020 - 49,453,297 and December 31, 2019 - 49,175,843)	—		—
Additional paid-in capital	5,008		5,004
Accumulated deficit	(7,437)		(5,370)
Accumulated other comprehensive loss	(23)		(23)
Total equity attributable to common stock	(2,452)		(389)
Equity attributable to noncontrolling interests	76		93
Total equity	(2,376)		(296)
TOTAL LIABILITIES AND EQUITY	$	4,930	$	6,958

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 and six months ended June 30, 2020 and 2019

(in millions, except share data)


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
REVENUES
Oil and natural gas sales	$	245	$	578	$	675	$	1,179
Net derivative (loss) gain from commodity contracts	(4)		21		75		(68)
Other revenue	35		54		99		232
Total revenues	276		653		849		1,343

COSTS
Production costs	127		230		319		463
General and administrative expenses	69		79		129		162
Depreciation, depletion and amortization	88		121		207		239
Asset impairments	—		—		1,736		—
Taxes other than on income	38		36		79		77
Exploration expense	2		10		7		20
Other expenses, net	67		55		136		203
Total costs	391		531		2,613		1,164

OPERATING (LOSS) INCOME	(115)		122		(1,764)		179

NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(85)		(98)		(172)		(198)
Net gain on early extinguishment of debt	—		20		5		26

Other non-operating expenses	(47)		(3)		(61)		(10)
(LOSS) INCOME BEFORE INCOME TAXES	(247)		41		(1,992)		(3)
Income tax	—		—		—		—
NET (LOSS) INCOME	(247)		41		(1,992)		(3)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	(30)		(29)		(60)		(57)
Equity	6		—		(15)		5
Net income attributable to noncontrolling interests	(24)		(29)		(75)		(52)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(271)	$	12	$	(2,067)	$	(55)

Net (loss) income attributable to common stock per share
Basic	$	(5.47)	$	0.25	$	(41.84)	$	(1.13)
Diluted	$	(5.47)	$	0.24	$	(41.84)	$	(1.13)

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 and six months ended June 30, 2020 and 2019

(in millions)


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
Net (loss) income	$	(247)	$	41	$	(1,992)	$	(3)
Net income attributable to noncontrolling interests	(24)		(29)		(75)		(52)
Other comprehensive income:
Reclassification of realized losses on pension and postretirement benefits to income^(a)	—		1		—		1
Comprehensive (loss) income attributable to common stock	$	(271)	$	13	$	(2,067)	$	(54)

^(a) No associated tax for the three and six months ended June 30, 2020 and 2019. See Note 10 Pension and Postretirement Benefit Plans for additional information.

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 and six months ended June 30, 2020

(in millions)


	Three months ended June 30, 2020
	Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, March 31, 2020	$	5,006	$	(7,166)	$	(23)	$	(2,183)	$	88	$	(2,095)
Net loss	—		(271)		—		(271)		(6)		(277)

Distributions to noncontrolling interest holders	—		—		—		—		(6)		(6)
Share-based compensation, net	2		—		—		2		—		2





Balance, June 30, 2020	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)


	Six months ended June 30, 2020
	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, 2019	$	5,004	$	(5,370)	$	(23)	$	(389)	$	93	$	(296)
Net (loss) income	—		(2,067)		—		(2,067)		15		(2,052)

Distributions to noncontrolling interest holders	—		—		—		—		(32)		(32)
Share-based compensation, net	4		—		—		4		—		4



Balance, June 30, 2020	$	5,008	$	(7,437)	$	(23)	$	(2,452)	$	76	$	(2,376)

Note: The above tables exclude amounts related to redeemable noncontrolling interests reported in mezzanine equity. See Note 6 Joint Ventures for more information.

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 and six months ended June 30, 2019

(in millions)


	Three months ended June 30, 2019
	Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Equity Attributable to Common Stock		Equity Attributable to Noncontrolling Interests		Total Equity
Balance, March 31, 2019	$	4,989	$	(5,409)	$	(6)	$	(426)	$	137	$	(289)
Net loss	—		12		—		12		—		12
Contributions from noncontrolling interest holders, net	—		—		—		—		—		—
Distributions to noncontrolling interest holders	—		—		—		—		(8)		(8)
Issuance of common stock	—		—		—		—		—		—
Other comprehensive income			—		1		1		—		1
Share-based compensation, net	5		—		—		5		—		5



Balance, June 30, 2019	$	4,994	$	(5,397)	$	(5)	$	(408)	$	129	$	(279)


	Six months ended June 30, 2019
	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, 2018	$	4,987	$	(5,342)	$	(6)	$	(361)	$	114	$	(247)
Net loss	—		(55)		—		(55)		(5)		(60)
Contributions from noncontrolling interest holders, net	—		—		—		—		49		49
Distributions to noncontrolling interest holders	—		—		—		—		(29)		(29)

Other comprehensive income	—		—		1		1		—		1
Share-based compensation, net	7		—		—		7		—		7

Balance, June 30, 2019	$	4,994	$	(5,397)	$	(5)	$	(408)	$	129	$	(279)

Note: The above tables exclude amounts related to redeemable noncontrolling interests reported in mezzanine equity. See Note 6 Joint Ventures for more information.

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 six months ended June 30, 2020 and 2019

(in millions)


	Six months ended June 30,
	2020		2019
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(1,992)	$	(3)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	207		239
Asset impairments	1,736		—
Net derivative (gain) loss from commodity contracts	(75)		68
Net proceeds from settled commodity derivatives	103		28
Net gain on early extinguishment of debt	(5)		(26)
Amortization of deferred gain	(33)		(36)

Dry hole expenses	—		7
Other non-cash charges to income, net	22		47
Changes in operating assets and liabilities, net	130		(52)
Net cash provided by operating activities	93		272

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(33)		(271)
Changes in capital investment accruals	(28)		(57)
Asset divestitures	41		165
Acquisitions	—		(2)
Other	(7)		(5)
Net cash used in investing activities	(27)		(170)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from 2014 Revolving Credit Facility	795		1,274
Repayments of 2014 Revolving Credit Facility	(582)		(1,289)
Debt repurchases	(3)		(59)

2020 Senior Notes payment	(100)		—
Contributions from noncontrolling interest holders, net	2		49
Distributions paid to noncontrolling interest holders	(68)		(65)
Issuance of common stock	—		1
Shares canceled for taxes	(1)		(3)
Net cash provided by (used in) financing activities	43		(92)
Increase in cash	109		10
Cash—beginning of period	17		17
Cash—end of period	$	126	$	27

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

June 30, 2020

NOTE 1 BASIS OF PRESENTATION

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We were incorporated in Delaware and became a publicly traded company on December 1, 2014. 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.

Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 cases filed by us (Chapter 11 Cases) are being jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). On July 24, 2020, we filed a Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court.

We continue to operate our business as “debtors-in-possession” (DIP) under the jurisdiction of the Bankruptcy Court and in accordance with the Bankruptcy Code. To ensure our ability to continue operating in the ordinary course of business and to minimize the effect of the Chapter 11 Cases on our employees, vendors and customers, we filed motions for customary “first day” relief with the Bankruptcy Court. On July 17, 2020, the Bankruptcy Court entered interim or final orders that included authorizing payments of pre-petition liabilities with respect to certain employee compensation and benefits, taxes, royalties, certain essential vendor payments and insurance and surety obligations. On July 21, 2020, the Bankruptcy Court approved on a final basis an order designed to assist us in preserving certain tax attributes. This order established the procedures that certain stockholders and potential stockholders will be required to comply with regarding transfers of, or declarations of worthlessness with respect to, our common stock as well as certain notice obligations. On July 22, 2020, the Bankruptcy Court approved on an interim basis a motion authorizing us to enter into DIP financing.

The commencement of the Chapter 11 Cases constitutes an event of default that accelerated our obligations under the following agreements: (i) Credit Agreement, dated as of September 24, 2014, among JPMorgan Chase Bank, N.A., as administrative agent, and the lenders that are party thereto (2014 Revolving Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The Bank of New York Mellon Trust Company, N.A., as collateral and administrative agent, and the lenders that are party thereto (2016 Credit Agreement), (iii) Credit Agreement, dated as of November 17, 2017, among The Bank of America Mellon Trust Company, N.A., as administrative agent, and the lenders that are party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes). Additionally, other events of default, including cross-defaults, are present under these debt agreements. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us, including exercising remedies as a result of any event of default. See Note 5 Debt for additional details about our debt.

Restructuring Support Agreement

On July 15, 2020, we entered into a Restructuring Support Agreement which was subsequently amended on July 24, 2020 (RSA). This RSA contemplates a restructuring plan that establishes a reorganized company with a new capital structure. The transactions contemplated by the RSA plan include (i) entering into a senior secured superpriority DIP credit facility (Senior DIP Facility) in an aggregate principal amount of up to approximately $483 million, (ii) entering into a junior secured superpriority DIP term loan facility in an aggregate amount of $650 million, (iii) the implementation of financing upon emergence from bankruptcy, (iv) the issuance of new common stock, and (v) a $450 million equity rights offering, backstopped by certain parties to the RSA.

The following creditors have entered into the RSA: (i) lenders holding approximately 85% of the outstanding principal amount of loans under the 2017 Credit Agreement, (ii) creditors holding approximately 68% of the aggregate claims arising under the 2016 Credit Agreement, the Second Lien Notes, the 2021 Notes and the 2024 Notes, and (iii) one or more funds, investment vehicles and/or accounts managed or advised by Ares Management LLC (Ares) or its affiliates, including ECR Corporate Holdings L.P. (ECR).

The transactions contemplated by the RSA, if approved, will result in current holders of our common stock receiving no distribution on account of their claims or interests. No assurance can be given that the Bankruptcy Court will approve the terms proposed under the RSA.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into (1) a Senior Secured Superpriority DIP Credit Agreement with JP Morgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement) and (2) a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement). For more information on our debtor-in-possession credit agreements, see Note 5 Debt.

Ares JV Settlement Agreement

On July 15, 2020, prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares, including ECR, entered into a settlement and assumption agreement (Settlement Agreement). On July 17, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on an interim basis pending a final hearing. Upon entry of a final order by the Bankruptcy Court, we will be granted the right to acquire all of the equity interests of the Ares JV owned by ECR in exchange for secured notes, cash and common stock upon emergence from bankruptcy. We have also agreed to certain covenants and amendments to the Ares JV limited liability company agreement. The Settlement Agreement may be terminated in certain limited circumstances. For more information on the Ares JV, see Note 6 Joint Ventures.

Ability to Continue as a Going Concern

Our spin–off from Occidental Petroleum Corporation (Occidental) on November 30, 2014 burdened us with significant debt which was used to pay a $6.0 billion cash dividend to Occidental. Together with the activity level and payables that we assumed from Occidental and due to Occidental's retention of the vast majority of our receivables, our debt peaked at approximately $6.8 billion in May 2015. Since then, we have engaged in a series of assets sales, joint ventures, debt exchanges, tenders and repurchases and other financing transactions to reduce our overall debt and improve our balance sheet. As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021.

We currently expect that our cash flows, cash on hand and financing available through our DIP credit agreements should provide sufficient liquidity during the pendency of the Chapter 11 Cases. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 Cases is also subject to a high degree of uncertainty and is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court, our creditors, and Ares. There can be no assurance that we will confirm and consummate the plan under the RSA or complete another plan of reorganization with respect to the Chapter 11 proceedings. There is substantial doubt that we can continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases.

For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 Cases. See Part II, Item 1A – Risk Factors, below for further discussion of these risks and risks related to our ability to continue as a going concern.

Basis of Presentation

The accompanying condensed consolidated financial statements have been prepared assuming we will continue as a going concern. These financial statements do not include any adjustments that might result from the outcome of our going concern uncertainty or the Chapter 11 Cases. Further, the Chapter 11 Cases could result in a change in the basis of our accounting, which may have a material effect on the carrying value of certain assets and liabilities.

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 as of June 30, 2020 and December 31, 2019 and the statements of operations, comprehensive income (loss), equity and cash flows for the three and six months ended June 30, 2020 and 2019, as applicable. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas exploration and development ventures, 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 balance sheets, statements of operations, equity and cash flows.

We have prepared this report in accordance with generally accepted accounting principles 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 not misleading. This Form 10-Q should be read in conjunction with the condensed consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2019.

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

We adopted the Financial Accounting Standards Board's new rules on current expected credit losses on January 1, 2020, using a modified retrospective approach to the first period in which the guidance is effective. The new rules change 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 will result in the earlier recognition of an allowance for losses. The adoption of these new rules did not have a significant impact to our condensed consolidated financial statements.

These rules apply to our trade receivables and joint interest billings to third-party customers. Credit exposure for each customer is monitored for outstanding balances and current activity. We actively manage our credit risk by selecting counterparties that we believe to be financially sound and continue to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified. We believe exposure to counterparty credit-related losses at June 30, 2020 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

NOTE 3 OTHER INFORMATION

Restricted cash — Cash at June 30, 2020 included $21 million which was restricted under agreements to fund operating expenses at one of our joint ventures and hold for distributions to a joint venture (JV) partner. Cash at December 31, 2019 included $3 million, which was restricted for distributions to a JV partner.

Other current assets, net — Other current assets, net as of June 30, 2020 and December 31, 2019 consisted of the following:


	June 30,		December 31,
	2020		2019
	(in millions)
Net amounts due from joint interest partners^(a)	$	50	$	70
Derivative assets^(b)	7		39
Prepaid expenses	27		19
Other	—		2
Other current assets, net	$	84	$	130

(a)Both June 30, 2020 and December 31, 2019 balances included $19 million in an allowance for credit losses against the receivables from our joint interest partners.

(b)Derivative assets at June 30, 2020 included only commodity contracts held by the Benefit Street Partners joint venture (BSP JV). Derivative assets at December 31, 2019 included commodity contracts for our hedge positions and those held by the BSP JV.

Accrued liabilities — Accrued liabilities as of June 30, 2020 and December 31, 2019 consisted of the following:


	June 30,		December 31,
	2020		2019
	(in millions)
Accrued employee-related costs^(a)	$	48	$	116
Accrued taxes other than on income^(b)	94		57
Accrued interest^(c)	154		13
Lease liability	15		28
Asset retirement obligations	28		28
Other^(d)	16		71
Accrued liabilities	$	355	$	313

(a)As of June 30, 2020, accrued employee-related costs declined $68 million primarily due to bonus, long term incentive and severance payments made to employees and former employees.

(b)Accrued taxes other than income increased $37 million as of June 30, 2020 primarily due to missed property tax payments in April 2020 as a result of the economic impact of Coronavirus Disease 2019 (COVID-19).

(c)Accrued interest increased $141 million as of June 30, 2020 primarily due to missed interest payments as described in Note 5 Debt.

(d)Other accrued liabilities declined $55 million as of June 30, 2020 primarily due to the timing of payments with joint interest partners and settlement payments.

Other long-term liabilities — Other long-term liabilities included asset retirement obligations of $499 million and $489 million at June 30, 2020 and December 31, 2019, respectively. The remainder of the balance for each year consisted primarily of postretirement and pension benefit obligations, liabilities related to deferred compensation arrangements and lease liabilities.

Supplemental Cash Flow Information

We did not make U.S. federal and state income tax payments during the six months ended June 30, 2020 and 2019. Interest paid, net of capitalized amounts, totaled $51 million and $219 million for the six months ended June 30, 2020 and 2019, respectively.

Fair Value of Financial Instruments

The carrying amounts of cash and other on-balance sheet financial instruments, other than debt, approximate fair value.

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 and net realizable value. Inventories as of June 30, 2020 and December 31, 2019 consisted of the following:


	June 30,		December 31,
	2020		2019
	(in millions)
Materials and supplies	$	59	$	64
Finished goods	2		3
Total	$	61	$	67

NOTE 5 DEBT

We have classified all our long-term debt as current due to events of default that occurred prior to June 30, 2020 and the commencement of the Chapter 11 Cases on July 15, 2020 as described below.

As of June 30, 2020 and December 31, 2019, our debt consisted of the following credit agreements, Second Lien Notes and Senior Notes:


	Outstanding Principal					Interest Rate		Security
	June 30, 2020		December 31, 2019
Credit Agreements	($ in millions)
2014 Revolving Credit Facility	$	731	$	518	LIBOR plus 3.25%-4.00% ABR plus 2.25%-3.00%		Shared First-Priority Lien
2017 Credit Agreement	1,300		1,300		LIBOR plus 4.75% ABR plus 3.75%		Shared First-Priority Lien
2016 Credit Agreement	1,000		1,000		LIBOR plus 10.375% ABR plus 9.375%		First-Priority Lien
Second Lien Notes
Second Lien Notes	1,808		1,815		8%		Second-Priority Lien
Senior Notes
5% Senior Notes due 2020	—		100		5%		Unsecured
5.5% Senior Notes due 2021	100		100		5.5%		Unsecured
6% Senior Notes due 2024	144		144		6%		Unsecured
Total Debt	$	5,083	$	4,977
Less: Current Portion of Long-Term Debt	(5,083)		(100)
Total Long-Term Debt	$	—	$	4,877

Note: For a detailed description of our credit agreements, Second Lien Notes and Senior Notes, please see our most recent Form 10-K for the year ended December 31, 2019.

The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the 2014 Revolving Credit Facility, 2016 Credit Agreement, 2017 Credit Agreement, and the indentures governing the Second Lien Notes, 2021 Notes and 2024 Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt. Any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed immediately upon the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. See Note 1 Basis of Presentation for more information on the Chapter 11 Cases.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into the Senior DIP Credit Agreement, which provides for the senior DIP facility in an aggregate principal amount of up to $483 million (Senior DIP Facility). The Senior DIP Facility includes a $250 million revolving facility which will be primarily used by us to (i) fund working capital needs and capital expenditures and additional letters of credit during the pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Senior DIP Facility. Until the Bankruptcy Court enters a final order with respect to our DIP credit agreements, only $85 million of revolving borrowings are available. If the Bankruptcy Court enters a final order approving the Senior DIP Facility in its current form following a hearing on August 14, 2020, we expect the full remaining amount of the $250 million revolving facility to become available. The Senior DIP Facility also includes (a) a $150 million letter of credit facility which was used to deem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (b) $83 million of term loan borrowings which were used to repay a portion of the 2014 Revolving Credit Facility.

On July 23, 2020, we entered into the Junior DIP Credit Agreement, which provides for a junior DIP facility in an aggregate principal amount of $650 million (Junior DIP Facility). The proceeds of the Junior DIP Facility were used to (i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility.

The Senior DIP Credit Agreement and Junior DIP Credit Agreement both contain representations, warranties, and covenants that are customary for DIP facilities of their type, including certain milestones applicable to the Chapter 11 Cases, compliance with an agreed budget, hedging on not less than 25% of our share of expected crude oil production for a specified period, and other customary limitations on additional indebtedness, liens, asset dispositions, investments, restricted payments and other negative covenants, in each case subject to exceptions. Additionally, the Senior DIP Credit Agreement and Junior DIP Credit Agreement require us to maintain (i) minimum liquidity over a rolling four-week period of not less than $50 million, and (ii) minimum liquidity at all times of not less than $35 million. The Senior DIP Credit Agreement and Junior DIP Credit Agreement also contain customary events of default for facilities of their type, including failure to achieve the milestones and the occurrence of certain events in the Chapter 11 Cases. If an event of default occurs or is continuing, the applicable administrative agent may accelerate repayment of the indebtedness outstanding under the Senior DIP Facility or the Junior DIP Facility.

Borrowings under the Senior DIP Facility bear interest at a rate of LIBOR plus 4.5% for LIBOR loans and ABR plus 3.5% for alternative base rate loans. We also agreed to pay an upfront fee equal to 1.0% on the commitment amount of the Senior DIP Facility and quarterly commitment fees of 0.5% on the undrawn portion of the Senior DIP Facility.

Borrowings under the Junior DIP Facility bear interest at a rate of LIBOR plus 9.0% for LIBOR loans and ABR plus 8.0% for alternate base rate loans. We also agreed to pay an upfront fee equal to 1.0% of the commitment amount funded on the closing date and a fronting fee to a fronting lender.

Certain of our subsidiaries, including each of the debtors in the Chapter 11 Cases, have guaranteed all obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement. To secure the obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement, we have granted liens on substantially all of our assets, whether now owned or hereafter acquired.

The Senior DIP Facility and the Junior DIP Facility both mature on January 15, 2021.

Net Deferred Gain and Issuance Costs

As of June 30, 2020 and December 31, 2019, net deferred gain and issuance costs consisted of the following:


	June 30, 2020^(a)		December 31, 2019
	(in millions)
Deferred gain	$	176	$	211
Issuance costs and original issue discounts	(51)		(65)
Net deferred gain and issuance costs	$	125	$	146

(a)Due to uncertainties at June 30, 2020 regarding default and the commencement of the Chapter 11 Cases on July 15, 2020, we have classified all our outstanding debt and associated deferred gain, unamortized debt issue costs and discounts as a current liability as of June 30, 2020. Refer to Note 1 Basis of Presentation for more information on the Chapter 11 Cases.

Missed Interest Payments and Forbearance

On May 15, 2020, we did not make an interest payment of approximately $4 million on our 2024 Notes. The indenture governing the 2024 Notes provides for a 30-day grace period and the payment was made on June 12, 2020.

On May 29, 2020, we did not pay approximately $51 million in the aggregate of interest due under our 2017 Credit Agreement and 2016 Credit Agreement. Our failure to make those interest payments constituted events of default under the 2017 Credit Agreement, 2016 Credit Agreement and, as a result of cross default, under the 2014 Revolving Credit Facility.

On June 2, 2020, we entered into forbearance agreements (Forbearance Agreements) with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement. Pursuant to the Forbearance Agreements, the lenders who are parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, initially through June 14, 2020 and subsequently through July 15, 2020.

On June 15, 2020, we did not make an interest payment of approximately $72 million on our Second Lien Notes. The indenture governing the Second Lien Notes (Second Lien Notes Indenture) provides for a 30-day grace period, which expired on July 15, 2020. A failure to pay the interest within the 30-day grace period would constitute an event of default under the Second Lien Notes Indenture and cross defaults under our other debt instruments and agreements. We did not make the July 15, 2020 interest payment and commenced bankruptcy proceedings.

2014 Revolving Credit Facility

As of June 30, 2020, we had no ability to borrow under our 2014 Revolving Credit Facility due to the Forbearance Agreements described above. As of June 30, 2020 and December 31, 2019, we had letters of credit outstanding of $152 million and $165 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

Note Repurchases

In the six months ended June 30, 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. In the six months ended June 30, 2019, we repurchased approximately $76 million in face value of our Second Lien Notes for $59 million in cash resulting in a pre-tax gain of $26 million, including the effect of unamortized deferred gain and issuance costs.

Fair Value

At June 30, 2020, we estimate the fair value of our debt, which is classified as Level 1, based on prices from known market transactions or quoted market prices for our instruments. At December 31, 2019, the fair value of the variable rate portion of our debt was based on other observable (Level 2) inputs. The estimated fair value of our debt at June 30, 2020 and December 31, 2019, including the fair value of the variable-rate portion, was $1.2 billion and $3.8 billion, respectively, compared to a carrying value of $5.1 billion and $5.0 billion, respectively.

NOTE 6 JOINT VENTURES

Noncontrolling Interests

The following table presents the changes in noncontrolling interests for our consolidated JVs, which are reported in equity and mezzanine equity on the condensed consolidated balance sheets for the six months ended June 30, 2020 and 2019:


	Equity Attributable to Noncontrolling Interest										Mezzanine Equity - Redeemable Noncontrolling Interests
	Ares JV		BSP JV		Total		Ares JV		Elk Hills Carbon JV		Total
	(in millions)
Balance, December 31, 2019	$	—	$	93	$	93	$	802	$	—	$	802
Net income (loss) attributable to noncontrolling interests	3		12		15		61		(1)		60
Contributions from noncontrolling interest holders, net	—		—		—		—		2		2

Distributions to noncontrolling interest holders	(3)		(29)		(32)		(36)		—		(36)
Balance, June 30, 2020	$	—	$	76	$	76	$	827	$	1	$	828

Balance, December 31, 2018	$	15	$	99	$	114	$	756	$	—	$	756
Net (loss) income attributable to noncontrolling interests	(6)		1		(5)		57		—		57
Contributions from noncontrolling interest holders, net	—		49		49		—		—		—

Distributions to noncontrolling interest holders	(4)		(25)		(29)		(36)		—		(36)
Balance, June 30, 2019	$	5	$	124	$	129	$	777	$	—	$	777

Ares JV

In February 2018, our wholly owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream JV with ECR, a portfolio company of Ares. The Ares JV holds the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. We hold 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR holds 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. The Ares JV is required to distribute each month its excess cash flow over its working capital requirements first to the Class B holders and then to the Class C common interests, on a pro-rata basis. As contemplated by the terms of the JV, CREH purchases electricity, steam and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which will be used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC. CREH also serves as the operator of the Ares JV and provides operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement.

We can cause the Ares JV to redeem ECR's Class A and Class B interests, in whole, but not in part, at any time by paying $750 million for the Class B interest and $60 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to five years from inception. We have the option to extend the redemption period for up to an additional two and one-half years, in which case the interests can be redeemed for $750 million for the Class B interest and $80 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to seven and one-half years from inception.

ECR can sell its Class A and Class B interest or cause a sale of the Ares JV assets in certain circumstances, which include but are not limited to the following: (i) we do not cause the Ares JV to exercise its option to redeem the Class A and Class B interest held by ECR by the end of the seven and one-half year redemption period, (ii) we fail to make payment for purchases of power or gas processing services followed by the failure to make a preferred distribution payment within 60 days, (iii) we default on indebtedness in excess of $100 million and such indebtedness is declared due and payable or (iv) we commence bankruptcy proceedings.

See Note 1 Basis of Presentation regarding our Chapter 11 Cases and the Settlement Agreement entered into relating to the Ares JV.

Our condensed consolidated statements of operations reflect the operations of the Ares JV, with ECR's share of net income (loss) reported in net income attributable to noncontrolling interests. ECR's redeemable noncontrolling interests are reported in mezzanine equity due to an embedded optional redemption feature.

Benefit Street Partners (BSP) JV

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 in our condensed consolidated statements of operations.

Elk Hills Carbon JV

In January 2020, we entered into an agreement with OGCI Climate Investments Elk Hills Carbon Inc. (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 scope and study. The project received financial assistance from the U.S. Department of Energy and project participants include us, Electric Power Research Institute, and Fluor Corporation. We formed Elk Hills Carbon LLC (Elk Hills Carbon JV) with OGCI to assist with the initial funding obligation. OGCI contributed approximately $2 million to the Elk Hills Carbon JV in February 2020.

Our condensed consolidated statements of operations reflect the operations of the Elk Hills Carbon JV, with OGCI's share of net income (loss) reported in net income attributable to noncontrolling interests. OGCI's redeemable noncontrolling interests are reported in mezzanine equity due to an optional redemption feature.

Other

In July 2019, we entered into a development joint venture with Alpine Energy Capital, LLC (Alpine) to develop portions of our Elk Hills field (Alpine JV). Alpine made an initial commitment to invest $320 million over a period of up to three years in accordance with a 275-well development plan. On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below $45 per barrel over a 30-trading day period. The suspension is automatically lifted and Alpine is obligated to renew funding at such time as the average price exceeds that threshold over any 30-trading day period. If prices remain below the threshold for over 100 consecutive trading days, the development phase may be terminated by us, subject to agreement by Alpine.

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. (MIRA JV), and the JV with Royale Energy, Inc. (Royale JV), please see our most recent Form 10-K for the year ended December 31, 2019.

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 June 30, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates. 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 accrued would not be material to our condensed consolidated financial statements taken as a whole.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of us or our property to recover on, collect or secure a claim arising prior to July 15, 2020 or to exercise control over property of our bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such action, or judicial or administrative proceeding. Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under regulatory powers.

NOTE 8 DERIVATIVES

We use a variety of derivative instruments in implementing our hedging program to protect our cash flow, operating margin and capital program from the cyclical nature of commodity prices and interest-rate movements. These derivatives are intended to help us maintain adequate liquidity and improve our ability to comply with the covenants of our credit facilities in case of price deterioration.

We did not have any derivative instruments designated as accounting hedges as of and during the three and six months ended June 30, 2020 and 2019. 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.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. On July 17, 2020, the Bankruptcy Court authorized us to engage in hedging activities. On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement.

Commodity-price risk — In March 2020, we monetized all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million. We recognized the proceeds received in net derivative gain (loss) from commodity contracts on our condensed consolidated statements of operations in the first quarter of 2020. We did not enter into any new hedges during the second quarter of 2020.

The BSP JV holds crude oil derivatives and natural gas swaps for insignificant volumes through 2021 that are included in our consolidated results. The hedges entered into by the BSP JV could affect the timing of the redemption of BSP's preferred interest.

The following table presents the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of June 30, 2020 and December 31, 2019:


June 30, 2020
Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
Assets:	(in millions)
Other current assets, net	$	7	$	—	$	7
Other assets	—		—		—

Liabilities:
Accrued liabilities	—		—		—

Total derivatives	$	7	$	—	$	7


December 31, 2019
Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
Assets:	(in millions)
Other current assets, net	$	49	$	(10)	$	39
Other assets	1		—		1

Liabilities:
Accrued liabilities	(15)		10		(5)

Total derivatives	$	35	$	—	$	35

Interest-rate risk — We hold derivative contracts that limit our interest-rate exposure with respect to $1.3 billion of our variable-rate indebtedness. These interest-rate contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR exceeds 2.75% for any monthly period prior to May 2021. For the quarters ended June 30, 2020 and 2019, we reported no change in fair value on these contracts in other non-operating expenses on our consolidated statements of operations.

Fair value of derivatives — 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 recognize fair value changes on derivative instruments in each reporting period. The changes in fair value result from the relationship between our existing positions, volatility, time to expiration, contract prices or interest rates and the associated forward curves.

NOTE 9 EARNINGS PER SHARE

We compute basic and diluted earnings per share (EPS) using the two-class method required for participating securities. Certain of our restricted and performance stock awards are considered participating securities because they have non-forfeitable dividend rights at the same rate as our common stock.

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 outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding all potentially dilutive securities.

The following table presents the calculation of basic and diluted EPS for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
Basic EPS calculation	(in millions, except per-share amounts)
Net (loss) income	$	(247)	$	41	$	(1,992)	$	(3)
Net income attributable to noncontrolling interests	(24)		(29)		(75)		(52)
Net loss (income) attributable to common stock	(271)		12		(2,067)		(55)


Weighted-average common shares outstanding — basic	49.5		48.9		49.4		48.8
Basic EPS	$	(5.47)	$	0.25	$	(41.84)	$	(1.13)

Diluted EPS calculation
Net (loss) income	$	(247)	$	41	$	(1,992)	$	(3)
Net income attributable to noncontrolling interests	(24)		(29)		(75)		(52)
Net loss (income) attributable to common stock	(271)		12		(2,067)		(55)


Weighted-average common shares outstanding — basic	49.5		48.9		49.4		48.8
Dilutive effect of potentially dilutive securities	—		0.3		—		—
Weighted-average common shares outstanding — diluted	49.5		49.2		49.4		48.8
Diluted EPS	$	(5.47)	$	0.24	$	(41.84)	$	(1.13)
Weighted-average anti-dilutive shares	5.2		1.9		4.9		2.6

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 and six months ended June 30, 2020 and 2019:


	Three months ended June 30,
	2020						2019
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)
Service cost	$	1	$	1	$	—	$	1
Interest cost	—		1		—		2
Expected return on plan assets	—		—		—		(1)
Recognized actuarial loss	—		—		—		1
Settlement loss	—		—		1		—
Total	$	1	$	2	$	1	$	3


	Six months ended June 30,
	2020						2019
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)
Service cost	$	1	$	2	$	—	$	2
Interest cost	1		2		1		3
Expected return on plan assets	—		—		(1)		(1)
Recognized actuarial loss	—		—		1		1
Settlement loss	—		—		1		—
Total	$	2	$	4	$	2	$	5

We did not make any significant contributions to our defined benefit pension plans for the three and six months ended June 30, 2020. The Coronavirus Aid, Relief, and Economic Security Act (CARES Act) became law on March 27, 2020 and allows 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 for the first six months of 2020 until December 2020. We made contributions of $1 million for the three months and six months ended June 30, 2019. The 2019 settlement losses, which were reclassified from accumulated other comprehensive income, were associated with early retirements.

NOTE 11 REVENUE RECOGNITION

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

The following table provides disaggregated revenue for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(in millions)
Oil and natural gas sales:
Oil	$	193	$	496	$	549	$	976
Natural gas	26		43		64		105
NGLs	26		39		62		98
	245		578		675		1,179
Other revenue:
Electricity	19		16		32		50
Marketing, trading and other	16		38		67		182

	35		54		99		232
Net derivative gain (loss) from commodity contracts	(4)		21		75		(68)
Total revenues	$	276	$	653	$	849	$	1,343

NOTE 12 LEASES

Balance sheet information related to our operating and finance leases as of June 30, 2020 and December 31, 2019 was as follows:



	Balance Sheet Location	June 30, 2020		December 31, 2019
		(in millions)		(in millions)
Right-of-Use Assets
Operating lease, net	Other assets	$	45	$	59
Finance lease, net	PP&E	1		2
Total right-of-use assets		$	46	$	61

Lease Liabilities
Current
Operating lease	Accrued liabilities	$	14	$	27
Finance lease	Accrued liabilities	1		1
Long-term
Operating lease	Other long-term liabilities	33		37
Finance lease	Other long-term liabilities	—		1
Total lease liabilities		$	48	$	66

Our operating lease assets and liabilities decreased from year end 2019 primarily due to releasing five of our leased drilling rigs in the first quarter of 2020 in response to the economic environment. Our remaining two leased drilling rigs have been cold stacked and were included with our proved properties in our impairment assessment as discussed in Note 14 Asset Impairments. These right-of-use assets were not impaired.

NOTE 13 INCOME TAXES

We estimate our annual effective income tax rate to record our quarterly provision in the jurisdictions in which we operate. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. We maintained a full valuation allowance against our net deferred tax assets after considering cumulative losses, including oil and natural gas asset impairments.

For the six months ended June 30, 2020 and 2019, we did not provide any current or deferred tax provision or benefit. The difference between our statutory tax rate and our effective tax rate of zero for the 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 level of profitability that we can achieve.

The CARES Act increased the limitation on the deductibility of business interest expense from 30% to 50% of adjusted taxable income in 2019 and 2020 along with other provisions intended to provide relief to corporate taxpayers. There was no impact on our income tax provision due to our full valuation allowance.

On July 28, 2020 the Internal Revenue Service (IRS) issued final and new proposed regulations related to the limitation on the deduction for business interest. We are in the process of evaluating the final and new proposed regulations, which may change the composition of our deferred tax assets, specifically the amount reported for net operating loss and business interest expense carryforwards. Due to our full valuation allowance position, these regulations are not expected to have a material impact to our financial statements.

NOTE 14 ASSET IMPAIRMENTS

We did not impair any of our long-lived assets during the three-month period ended June 30, 2020, but recorded a $1.7 billion impairment during the three-month period ended March 31, 2020. Our impairments of long-lived assets were triggered by the sharp drop in commodity prices due to decreased 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) and Russia and other allied producing countries. The following table presents a summary of our asset impairments:


	Six months ended
	June 30, 2020
	(in millions)
Proved oil and natural gas properties	$	1,487
Unproved properties	228
Unrecovered capital costs	11
Inventory	7
Other	3
Total	$	1,736

Proved oil and natural gas properties — The fair values of our proved oil and natural gas properties were determined as of the date of the assessment using discounted cash flow models incorporating a number of fair value inputs which are categorized as Level 3 on the fair value hierarchy. These inputs were based on management's expectations for the future considering the current environment and included index prices based on forward curves until the market became illiquid and internally generated price forecasts thereafter, pricing adjustments for differentials, estimates of future oil and natural gas production, estimated future operating costs and capital development plans based on the embedded price assumptions. We used a market-based weighted average cost of capital to discount the future net cash flows. The impairment charge primarily related to a steamflood property located in the San Joaquin basin.

Unproved properties — We determined our ability to develop our unproved properties was constrained for the foreseeable future. Accordingly, we do not intend to develop these assets and impaired all of our unproved properties in the first quarter of 2020, which primarily consist of leases held by production in the San Joaquin basin.

Unrecovered capital costs — Net amounts due from joint interest partners, which are included in other current assets on our condensed consolidated balance sheet, include amounts for capital and operating costs incurred by us that are 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 assets.

NOTE 15 COMPENSATION PLANS

Changes to the 2020 Compensation Programs

In connection with the unprecedented circumstances affecting the industry and market volatility resulting from the recent industry downturn, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately align compensation opportunities with our 2020 goals and ensure the stability of our workforce. Following this review, effective May 19, 2020, our Board of Directors approved changes in the variable compensation programs for all participating employees. The previously established target amounts of 2020 variable compensation programs did not change; however, all amounts that vest will be settled in cash and the replacement awards are no longer stock-based compensation. As a condition to receiving any award, participants waived participation in our 2020 annual incentive program and forfeited all stock-based compensation awards previously granted in 2020. There were no changes to stock-based compensation awards granted prior to February 2020. Changes to the variable compensation programs will have the effect of accelerating the associated payments into 2020 from future periods. However, the total amount of compensation to be paid under the variable compensation programs at target for 2020 remains largely the same as the amounts that would have been paid at target prior to the changes.

Employee Stock Purchase Plan

On May 26, 2020, our Board of Directors approved the termination of the California Resources Corporation 2014 Employee Stock Purchase Plan. No additional shares were issued under the plan after March 31, 2020.

NOTE 16 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our Credit Facilities, Second Lien Notes and Senior Notes are guaranteed both fully and unconditionally and jointly and severally by our material wholly owned subsidiaries (Guarantor Subsidiaries). Certain of our subsidiaries do not guarantee our Credit Facilities, Second Lien Notes and Senior Notes (Non-Guarantor Subsidiaries) either because they hold assets that are less than 1% of our total consolidated assets or because they are not considered a "subsidiary" under the applicable financing agreement. The following condensed consolidating balance sheets as of June 30, 2020 and December 31, 2019 and the condensed consolidating statements of operations and statements of cash flows for the three and six months ended June 30, 2020 and 2019, as applicable, reflect the condensed consolidating financial information of our parent company, CRC (Parent), our combined Guarantor Subsidiaries, our combined Non-Guarantor Subsidiaries and the elimination entries necessary to arrive at the information for the Company on a consolidated basis.

The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.


Condensed Consolidating Balance Sheets
As of June 30, 2020 and December 31, 2019
(in millions)

	June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	22	$	341	$	68	$	(28)	$	403
Investments in consolidated subsidiaries	3,156		(53)		—		(3,103)		—
Total property, plant and equipment, net	24		3,972		453		—		4,449
Other assets	1		64		13		—		78
TOTAL ASSETS	$	3,203	$	4,324	$	534	$	(3,131)	$	4,930

Total current liabilities	5,409		371		7		(28)		5,759


Other long-term liabilities	159		557		3		—		719
Amounts due to (from) affiliates	87		(88)		1		—		—
Mezzanine equity	—		—		828		—		828
Total equity	(2,452)		3,484		(305)		(3,103)		(2,376)
TOTAL LIABILITIES AND EQUITY	$	3,203	$	4,324	$	534	$	(3,131)	$	4,930


	December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	8	$	436	$	60	$	(13)	$	491
Investments in consolidated subsidiaries	5,956		223		—		(6,179)		—
Total property, plant and equipment, net	35		5,846		471		—		6,352
Other assets	1		82		32		—		115
TOTAL ASSETS	$	6,000	$	6,587	$	563	$	(6,192)	$	6,958

Total current liabilities	248		469		5		(13)		709
Long-term debt	4,877		—		—		—		4,877
Deferred gain and issuance costs, net	146		—		—		—		146
Other long-term liabilities	167		549		4		—		720
Amounts due to (from) affiliates	951		(953)		2		—		—
Mezzanine equity	—		—		802		—		802
Total equity	(389)		6,522		(250)		(6,179)		(296)
TOTAL LIABILITIES AND EQUITY	$	6,000	$	6,587	$	563	$	(6,192)	$	6,958


Condensed Consolidating Statements of Operations
For the three and six months ended June 30, 2020 and 2019
(in millions)

	Three months ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	253	$	94	$	(71)	$	276
Total costs	55		357		50		(71)		391
Non-operating (loss) income	(135)		3		—		—		(132)
NET (LOSS) INCOME	(190)		(101)		44		—		(247)
Net income attributable to noncontrolling interests	—		—		(24)		—		(24)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(190)	$	(101)	$	20	$	—	$	(271)


	Three months ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	610	$	113	$	(70)	$	653
Total costs	52		490		59		(70)		531
Non-operating (loss) income	(83)		2		—		—		(81)
NET (LOSS) INCOME	(135)		122		54		—		41
Net income attributable to noncontrolling interest	—		—		(29)		—		(29)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(135)	$	122	$	25	$	—	$	12


	Six months ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	779	$	210	$	(140)	$	849
Total costs	102		2,546		105		(140)		2,613
Non-operating (loss) income	(230)		2		—		—		(228)
NET (LOSS) INCOME	(332)		(1,765)		105		—		(1,992)
Net income attributable to noncontrolling interest	—		—		(75)		—		(75)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(332)	$	(1,765)	$	30	$	—	$	(2,067)


	Six months ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	1,255	$	235	$	(147)	$	1,343
Total costs	106		1,074		131		(147)		1,164
Non-operating (loss) income	(187)		5		—		—		(182)
NET (LOSS) INCOME	(293)		186		104		—		(3)
Net income attributable to noncontrolling interest	—		—		(52)		—		(52)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(293)	$	186	$	52	$	—	$	(55)


Condensed Consolidating Statements of Cash Flows
For the six months ended June 30, 2020 and 2019
(in millions)

	Six months ended June 30, 2020
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash (used in) provided by operating activities	$	(338)	$	277	$	154	$	—	$	93
Net cash provided by (used in) investing activities	1		(28)		—		—		(27)
Net cash provided by (used in) financing activities	340		(153)		(144)		—		43
Increase in cash	3		96		10		—		109
Cash—beginning of period	—		6		11		—		17
Cash—end of period	$	3	$	102	$	21	$	—	$	126


	Six months ended June 30, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash (used in) provided by operating activities	$	(348)	$	303	$	317	$	—	$	272
Net cash used in investing activities	(5)		(154)		(11)		—		(170)
Net cash provided by (used in) financing activities	353		(149)		(296)		—		(92)
Increase in cash	—		—		10		—		10
Cash—beginning of period	—		7		10		—		17
Cash—end of period	$	—	$	7	$	20	$	—	$	27

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

General

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.

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We are incorporated in Delaware and became a publicly traded company on December 1, 2014. On July 15, 2020, we filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code as further described below.

Our condensed consolidated financial statements, including the Notes thereto, included in Part I, Item – Financial Statements have been prepared assuming we will continue as a going concern. These financial statements do not include any adjustments that might result from the outcome of our going concern uncertainty or the Chapter 11 Cases (as defined below). There is substantial doubt that we can continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases as discussed below. Further, the Chapter 11 Cases could result in a change in the basis of our accounting, which may have a material effect on the carrying value of certain assets and liabilities.

Business Environment and Industry Outlook

Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly as a result of numerous market-related variables, especially given current global geopolitical and economic conditions. These and other factors make it impossible to predict realized prices reliably.

Prices for oil and gas products in the first half of 2020 have been strongly influenced by the Coronavirus Disease 2019 (COVID-19) pandemic and by the actions of foreign producers. The COVID-19 pandemic caused an unprecedented demand collapse due to the shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices. In addition, members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia did not extend existing oil production cuts expiring on April 1, 2020, and Saudi Arabia and Russia announced significant increases in crude oil production. The unprecedented dual impact of a severe global oil demand decline due to the COVID-19 pandemic repercussions coupled with a substantial increase in supply from Saudi Arabia and Russia resulted in a collapse in crude oil prices.

Reduced demand caused shortages in available storage facilities globally and required many oil and gas producers to shut in wells or curtail production. In April 2020, oil prices continued to decline precipitously temporarily reaching negative values for spot WTI crude. In May 2020 and June 2020, oil prices began to recover as producers across the world, including OPEC, Russia, the United States and others started cutting their production levels sharply and announced significant capital reductions, and an easing of shelter-in-place restrictions created partial demand recovery. However, demand and pricing may again decline due to the resurgence of the outbreak across parts of the United States and related re-imposition of certain restrictions. The current futures forward curve for Brent crude indicates that prices may continue at close to current levels but lower than pre-pandemic levels for an extended period of time.

We continue to closely monitor the impact of COVID-19, which negatively impacted our business and results of operations beginning in the first quarter of 2020. The lower commodity prices have continued into the second quarter and are currently expected to remain depressed for an extended period of time based on current futures curves. The extent to which our total year operating results will be impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning potential vaccines, the severity of the pandemic and actions taken to contain it or actions taken by government authorities or other producers in response to commodity price movements, among other things. See Part II, Item 1A – Risk Factors, below for further discussion regarding the impact of the pandemic and declines in commodity prices.

The following table presents the average daily Brent, WTI and NYMEX prices for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
Brent oil ($/Bbl)	$	33.27	$	68.32	$	42.12	$	66.11
WTI oil ($/Bbl)	$	27.85	$	59.82	$	37.01	$	57.36
NYMEX gas ($/MMBtu)	$	1.77	$	2.66	$	1.91	$	2.95

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

Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code

In light of our significant indebtedness and the unprecedented impact to our financial position resulting from the commodity price environment and the COVID-19 pandemic, combined with continued challenging conditions in the credit and capital markets, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court) on July 15, 2020. The Chapter 11 cases filed by us (Chapter 11 Cases) are being jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). On July 24, 2020, we filed a Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court.

Restructuring Support Agreement

On July 15, 2020, we entered into a Restructuring Support Agreement which was subsequently amended on July 24, 2020 (RSA). This RSA contemplates a restructuring plan that establishes a reorganized company with a new capital structure. The transactions contemplated by the RSA plan include (i) entering into a senior secured superpriority DIP credit facility (Senior DIP Facility) in an aggregate principal amount of up to approximately $483 million, (ii) entering into a junior secured superpriority DIP term loan facility in an aggregate amount of $650 million (Junior DIP Facility), (iii) the implementation of financing upon emergence from bankruptcy, (iv) the issuance of new common stock, and (v) a $450 million equity rights offering, backstopped by certain parties to the RSA.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into (1) a Senior Secured Superpriority DIP Credit Agreement with JPMorgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement) and (2) a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement). For more information on our debtor-in-possession credit agreements, see Part I, Item 1 – Financial Statements, Note 5 Debt and Liquidity and Capital Resources below.

Ares JV Settlement Agreement

Going Concern Analysis and Recent Developments

Operations

Response to COVID-19 Pandemic and Industry Downturn

We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity.

In response to the rapid fall in commodity prices, we reduced our 2020 capital budget to a level that maintains the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner and ceased all field development and growth projects. As a result, our internally funded capital was $3 million in the second quarter of 2020. We also monetized all of our crude oil hedges for April 2020 forward with our counterparties, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to enhance our liquidity. We shut in certain wells to reduce operating costs which curtailed average gross production volumes by approximately 6 MBoe/d and average net production volumes by 5 MBoe/d during the second quarter of 2020. As part of our operational efficiency measures, we evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs. Our teams utilized our extensive automation controls, monitored weekly well margins, and made temporary adjustments to our producing wells to ensure our operations aligned with the price environment. As a result of these actions, as well as further cost rationalization and streamlining efforts coupled with lower activity levels, our current operating expense run rate is below $45 million per month compared to the first quarter average of $64 million per month. At our current level of capital investment, we anticipate production will continue to decline at a moderate pace through the remainder of the year.

We have also implemented various measures to protect the health of our workforce and to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. These initiatives were in accordance with the orders and guidance of federal, state and local authorities to mitigate the risks of the disease, and included temporarily closing all our administrative offices and implementing remote working for most office employees. As a result, our management team and substantially all of our office personnel, including finance and accounting teams, worked remotely beginning in March 2020. In June 2020, we began a phased return to the office, focused on those employees for whom remote work was not feasible. In addition, on April 6, 2020, we implemented reduced work hours for nearly all of our office employees and reduced salaries for our management team, in each case on a temporary basis that ended in May 2020. These reductions were made in an effort to preserve liquidity after the further deterioration of commodity prices following the outbreak of COVID-19. Our operational employees and contractors and certain support personnel have been classified as an essential critical infrastructure workforce by government authorities and continue to work in their plant, rig, field and office locations under our COVID-19 Health and Safety Plan that includes protocols for reporting of illness, self-quarantine, hygiene, applying social distancing to minimize close contact between workers, cleaning or disinfection of workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce.

Our Operations

We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. We are the largest private oil and natural gas mineral acreage holder in California, with interests in 2.2 million net mineral acres, approximately 60% of which is held in fee and 17% is held by production. Our oil and gas leases have primary terms ranging from one to ten years. Once production commences, the leases are typically extended on the producing acreage through the end of their producing life. As a result of our large mineral acre position held in fee, we generally have the flexibility to shut in wells while retaining our oil and gas leases which are held by production.

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.

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 gas reserves we can economically produce over the longer term. With our significant land holdings in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities, agricultural activities and other commercial uses.

Our share of production and reserves from operations in the Wilmington field 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 production costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and production 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 production costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 20% of our net production for the quarter ended June 30, 2020.

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 costs but only our net share of production equally inflates our revenue and operating costs and has no effect on our net results.

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

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

California is heavily reliant on imported sources of energy, with approximately 72% 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 continue to receive a premium in comparison to other comparable grades due to the demand for our product in the state of California. 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 monthly basis at market-based index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity from producing areas. Transportation capacity influences prices because California imports approximately 90% of its natural gas from other states and Canada. As a result, we typically enjoy favorable 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 even a smaller percentage of our revenue is from natural gas.

In addition to selling natural gas, we also use natural gas for our steamfloods and power generation. As a result, 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 higher revenue. Conversely, lower natural gas prices lower the operating costs but have a net negative effect on our financial results.

We currently have sufficient firm transportation capacity contracts to transport our natural gas, where some capacity volumes vary by month. We sell virtually all of our natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis.

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 pricing volatility.

Our earnings are also affected by the performance of our complementary processing and power-generation assets. 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. Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually delivered. In connection with another pipeline delivery contract that we assumed from Occidental, we made a one-time deficiency payment of $20 million in April 2020 when the contract expired. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 28% 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 operating costs and increases reliability. We sell the excess electricity generated to the grid and a local utility. The power sold to the utility is subject to agreements through the end of 2023, which include a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. The prices obtained for excess power impact our earnings but generally by an insignificant amount.

Derivatives and Hedging Activities

We opportunistically seek strategic hedging transactions to help protect our cash flow, operating margin and capital program from both the cyclical nature of commodity prices and interest rate movements while maintaining adequate liquidity and improving our ability to comply with our debt covenants. We can give no assurance that our hedging programs will be adequate to accomplish our objectives. In early March 2020, in response to the rapid fall in commodity prices, we monetized all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million to enhance our liquidity. As of June 30, 2020, we did not have any commodity hedges covering our share of production.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement. 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.

Development Joint Ventures

We have a number of joint ventures that have allowed us to accelerate the development of our assets which provided us with operational and financial flexibility as well as near-term production benefits. The following table summarizes the cumulative investment through June 30, 2020 by our development joint venture partners, before transaction costs:


	Cumulative Investment through
	June 30, 2020
	(in millions)
Alpine	$	231
Royale	17
MIRA	139
BSP	200
Total Capital Investment	$	587

For more information on our development joint ventures, please see our most recent Form 10-K for the year ended December 31, 2019.

Alpine JV

In July 2019, we entered into a development agreement with Alpine Energy Capital, LLC (Alpine). Alpine has committed to invest $320 million, which may be increased to a total investment of $500 million subject to the mutual agreement of the parties. The initial $320 million commitment covers multiple development opportunities and is intended to be invested over a period of up to three years in accordance with a 275-well development plan.

On March 27, 2020, Alpine elected to suspend its funding obligations pursuant to a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below $45 per barrel over a 30-trading day period. The suspension is automatically lifted and Alpine is obligated to renew funding at such time as the average price exceeds that threshold over any 30-trading day period. If prices remain below the threshold for over 100 consecutive trading days, the development phase may be terminated by us, subject to agreement by Alpine.

Ares JV

In February 2018, our wholly owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream joint venture with ECR, a portfolio company of Ares. The Ares JV holds the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. We hold 50% of the Class A common interests and 95.25% of the Class C common interests in the Ares JV. ECR holds 50% of the Class A common interests, 100% of the Class B preferred interests and 4.75% of the Class C common interests. As contemplated by the terms of the joint venture, CREH purchases electricity, steam and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which will be used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC. CREH also serves as the operator of the Ares JV and provides operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement.

For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 6 Joint Ventures. For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 1 Basis of Presentation.

Fixed and Variable Costs

Our production 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. As a result of the measures taken to address the recent industry downturn, we continue to believe approximately one-third of our operating costs are fixed over the life cycle of our fields and the remaining two-thirds costs are variable. We actively manage our fields to optimize production and minimize costs. When we see growth in a field, we increase capacities and, similarly, when a field nears the end of its economic life, we manage the costs while it remains economically viable to produce.

Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,			Six months ended June 30,
	2020	2019	2020	2019
Oil (MBbl/d)
San Joaquin Basin	41	52	44	54
Los Angeles Basin	27	23	26	24
Ventura Basin	2	4	3	4

Total	70	79	73	82
NGLs (MBbl/d)
San Joaquin Basin	13	15	14	14

Ventura Basin	—	1	—	1

Total	13	16	14	15
Natural gas (MMcf/d)
San Joaquin Basin	148	164	151	164
Los Angeles Basin	2	3	2	3
Ventura Basin	3	6	4	6
Sacramento Basin	21	30	22	29
Total	174	203	179	202

Total Net Production (MBoe/d)	112	129	117	131

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 June 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 17 MBoe/d or 13%. The decrease in production largely represented base decline resulting from low internal capital investment, the temporary shut in of certain wells beginning in March 2020 and the effect of the May 2019 partial divestiture of the Lost Hills field. The shut in wells and the Lost Hills divestiture reduced our second quarter 2020 net production by 7 MBoe/d. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the second quarter of 2020 by over 5 MBoe/d compared to the same period in 2019. Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was below 12%, which is in line with our range of stated base decline rates.

For the six months ended June 30,2020 compared to the same period in 2019, total daily production decreased by approximately 14 MBoe/d or 11%. The decrease in production largely represented base decline resulting from low internal capital investment, shut in production and the effect of the May 2019 partial divestiture of the Lost Hills field. The shut in wells and the Lost Hills divestiture reduced our net production for the six months ended June 30, 2020 by 7 MBoe/d. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the first half of 2020 by over 4 MBoe/d compared to the same period in 2019. Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was approximately 8%.

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 and six months ended June 30, 2020 and 2019:


	Three months ended June 30,
	2020					2019
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	33.27		$	68.32

Realized price without hedge	$	30.27	91%	$	68.77	101%
Settled hedges	0.55			1.89
Realized price with hedge	$	30.82	93%	$	70.66	103%

WTI	$	27.85		$	59.82
Realized price without hedge	$	30.27	109%	$	68.77	115%
Realized price with hedge	$	30.82	111%	$	70.66	118%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	21.05	63%	$	27.82	41%
Realized price (% of WTI)	$	21.05	76%	$	27.82	47%

Natural gas
NYMEX ($/MMBtu)	$	1.77		$	2.66

Realized price without hedge ($/Mcf)	$	1.65	93%	$	2.33	88%
Settled hedges	0.08			0.03
Realized price with hedge ($/Mcf)	$	1.73	98%	$	2.36	89%


	Six months ended June 30, 2020
	2020					2019
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	42.12		$	66.11

Realized price without hedge	$	41.02	97%	$	65.97	100%
Settled hedges	2.74			1.93
Realized price with hedge^(a)	$	43.76	104%	$	67.90	103%

WTI	$	37.01		$	57.36
Realized price without hedge	$	41.02	111%	$	65.97	115%
Realized price with hedge	$	43.76	118%	$	67.90	118%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	25.18	60%	$	34.97	53%
Realized price (% of WTI)	$	25.18	68%	$	34.97	61%

Natural gas
NYMEX ($/MMBtu)	$	1.91		$	2.95

Realized price without hedge ($/Mcf)	$	1.96	103%	$	2.87	97%
Settled hedges	0.09			(0.01)
Realized price with hedge ($/Mcf)	$	2.05	107%	$	2.86	97%

(a) Prices for the first six months of 2020 exclude the effect of $63 million of proceeds received in the first quarter of 2020 from settling derivative contracts with counterparties prior to maturity.

Oil — Brent index and realized prices were lower in both the three and six months ended June 30, 2020 compared to the same prior-year period due to the combination of the supply increase caused by the Saudi-Russia price war and the severe demand decline caused by COVID-19. Further, our realizations without hedge were significantly affected in the three months ended June 30, 2020, and to a lesser extent in the six months ended June 30, 2020, primarily due to the unprecedented global oversupply of oil and Saudi Arabia's price cuts for oil to the U.S. and other markets in April 2020. These two events led to lower crude realizations for foreign oil imported into California and depressed prices for native California crude.

NGLs — Prices for NGLs decreased from the same prior-year period as supply associated with high gas-producing basins outpaced steady demand, causing lower domestic NGL prices in the three and six months ended June 30, 2020. We continue to receive premium prices for NGLs relative to national hub prices.

Natural Gas — Our natural gas realized prices were lower in both the three and six months ended June 30, 2020 than the comparable periods of 2019. The decrease was due to increased nationwide natural gas production and lower demand resulting from the shelter-in-place orders related to COVID-19 that began in March 2020. Prices were also negatively impacted by lower supply constraints on the SoCalGas system in 2020 compared to the same period in the prior year.

Balance Sheet Analysis

The following table sets forth changes in our balance sheet between June 30, 2020 and December 31, 2019:


	June 30,		December 31,
	2020		2019
	(in millions)
Cash	$	126	$	17
Trade receivables	$	132	$	277
Inventories	$	61	$	67
Other current assets, net	$	84	$	130
Property, plant and equipment, net	$	4,449	$	6,352
Other assets	$	78	$	115
Current portion of long-term debt	$	5,083	$	100
Current deferred gain and issuance costs, net	$	125	$	—
Accounts payable	$	196	$	296
Accrued liabilities	$	355	$	313
Long-term debt	$	—	$	4,877
Deferred gain and issuance costs, net	$	—	$	146
Other long-term liabilities	$	719	$	720
Mezzanine equity	$	828	$	802
Equity attributable to common stock	$	(2,452)	$	(389)
Equity attributable to noncontrolling interests	$	76	$	93

Cash — Cash at June 30, 2020 and December 31, 2019 included restricted cash of $21 million and $3 million, respectively. See Liquidity and Capital Resources for our cash flow analysis.

Trade receivables — The decrease in trade receivables was largely driven by lower realized product prices and lower production volumes in June 2020 compared to December 2019.

Other current assets, net — The decrease in other current assets, net was primarily due to the sale of our crude oil hedge positions resulting in a decrease in the fair value of the current portion of our derivative assets. Additionally, in March 2020, we recorded an $11 million impairment on capital investments to be recovered from our joint interest partners solely from production.

Property, plant and equipment, net — The decrease in property, plant and equipment, net primarily reflected the $1.7 billion impairment of certain of our proved and unproved properties recorded in the first quarter of 2020, depreciation, depletion, and amortization (DD&A) and to a lesser extent sales of certain royalty interests and non-core assets in the first quarter of 2020. The decrease was partially offset by capital investments including the planned major maintenance at our Elk Hills power plant. For further detail about the asset impairment, see Part I, Item 1 – Financial Statements, Note 14 Asset Impairments.

Other assets — Other assets decreased primarily due to utilizing parts for the planned major maintenance of our Elk Hills power plant as well as a decrease in operating lease assets due to releasing drilling rigs in the first quarter of 2020.

Current portion of long-term debt — The increase in the current portion of long-term debt was a result of the reclassification of our long-term debt to current as described in Part I, Item 1 – Financial Statements, Note 5 Debt.

Current portion of deferred gain and issuance costs, net — The increase in the current portion of deferred gain and issuance costs, net was primarily a result of reclassifying capitalized costs associated with our long-term debt to current.

Accounts payable — The decrease in accounts payable was due to lower amounts payable to vendors following the reduction of our capital plan in the second quarter of 2020 compared to the fourth quarter of 2019.

Accrued liabilities — The increase in accrued liabilities primarily related to an increase in accrued interest as a result of our failure to make certain interest payments and property tax payments during the second quarter of 2020 compared to balances due as of the fourth quarter of 2019. These amounts were partially offset by the bonus payments to employees made in the first quarter of 2020 with respect to 2019 performance as well as a decrease in activities of the Alpine JV following their suspension of further capital funding due to low commodity prices.

Long-term debt — The decrease in long-term debt resulted from the reclassification of long-term debt to current as of June 30, 2020.

Deferred gain and issuance costs, net — The decrease in deferred gain and issuance costs, net resulted from the reclassification of costs associated with our long-term debt to current as of June 30, 2020.

Mezzanine equity — The increase in mezzanine equity primarily resulted from the preferred return to the Class B interests held by the noncontrolling interest partner in our Ares JV.

Equity attributable to common stock — Equity attributable to common stock decreased primarily as a result of the net loss in the six months ended June 30, 2020.

Statements of Operations Analysis

Results of Oil and Gas Operations

The following represents key operating data for our oil and gas operations, excluding certain corporate items, on a per Boe basis for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
Production costs	$	12.42	$	19.62	$	14.99	$	19.54
Production costs, excluding effects of PSC-type contracts^(a)	$	12.00	$	17.98	$	14.33	$	17.99
Field general and administrative expenses^(b)	$	1.17	$	1.28	$	1.08	$	1.27
Field depreciation, depletion and amortization^(b)	$	7.82	$	9.55	$	8.98	$	9.47
Field taxes other than on income^(b)	$	2.84	$	2.39	$	2.96	$	2.53

(a)As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts represent our production costs after adjusting for this difference.

(b)Excludes corporate expenses.

Consolidated Results of Operations

The following represents key operating data for our consolidated operations for the three and six months ended June 30, 2020 and 2019:


	Three months ended June 30,									Six months ended June 30,
	2020			2019			2020			2019
	(in millions)
Oil and natural gas sales	$	245		$	578		$	675		$	1,179
Net derivative (loss) gain from commodity contracts	(4)			21			75			(68)
Other revenue	35			54			99			232
Production costs	(127)			(230)			(319)			(463)
General and administrative expenses	(69)			(79)			(129)			(162)
Depreciation, depletion and amortization	(88)			(121)			(207)			(239)
Asset impairments	—			—			(1,736)			—
Taxes other than on income	(38)			(36)			(79)			(77)
Exploration expense	(2)			(10)			(7)			(20)
Other expenses, net	(67)			(55)			(136)			(203)
Interest and debt expense, net	(85)			(98)			(172)			(198)
Net gain on early extinguishment of debt	—			20			5			26

Other non-operating expenses	(47)			(3)			(61)			(10)
(Loss) income before income taxes	(247)			41			(1,992)			(3)
Income tax	—			—			—			—
Net (loss) income	(247)			41			(1,992)			(3)
Net income attributable to noncontrolling interests	(24)			(29)			(75)			(52)
Net (loss) income attributable to common stock	$	(271)		$	12		$	(2,067)		$	(55)

Adjusted net (loss) income^(a)	$	(202)		$	(14)		$	(210)		$	17
Adjusted EBITDAX^(a)	$	19		$	255		$	270		$	556
Effective tax rate	—		%	—		%	—		%	—		%

(a)Adjusted net (loss) income and adjusted EBITDAX are non-GAAP measures. See the Non-GAAP Financial Measures section below for reconciliations to their nearest U.S. GAAP equivalent.

Three months ended June 30, 2020 vs. 2019

Oil and natural gas sales — Oil and natural gas sales decreased 58%, or $333 million, for the three months ended June 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended June 30, 2019	$	496	$	39	$	43	$	578
Changes in realized prices	(279)		(10)		(13)		(302)
Changes in production	(24)		(3)		(4)		(31)
Three months ended June 30, 2020	$	193	$	26	$	26	$	245

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. Net proceeds from settled hedges were $5 million for the three months ended June 30, 2020 compared to net proceeds of $14 million for the same period of 2019, which had a negative impact of $9 million on our total revenue between periods. Including the effect of settled hedges, our oil and natural gas revenue decreased by $342 million or 58% compared to the same prior-year period.

Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $4 million for the three months ended June 30, 2020 compared to a gain of $21 million in the same period of 2019, representing an overall change of $25 million as reflected in the following table. 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, volatility, time to expiration and the associated forward curves.


	Three months ended June 30,
	2020		2019
	(in millions)
Non-cash derivative (loss) gain, excluding noncontrolling interest	$	—	$	4
Non-cash derivative (loss) gain, noncontrolling interest	(9)		3
Total non-cash changes	(9)		7
Net proceeds on settled commodity derivatives	5		14

Net derivative (loss) gain	$	(4)	$	21

Other revenue — The decrease in other revenue of $19 million to $35 million for the three months ended June 30, 2020 compared to $54 million in the same period of 2019 was primarily due to lower natural gas trading activity.

Production costs — Production costs for the three months ended June 30, 2020 decreased $103 million to $127 million compared to $230 million for the same period of 2019, resulting in a 45% decrease. The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our October 2019 workforce reduction and reduced work schedules during the months of April and May 2020. The operating costs of shut in wells, as well as lower activity levels in response to the current environment, such as downhole maintenance, also contributed to the decrease.

General and administrative expenses — Our general and administrative (G&A) expenses decreased $10 million to $69 million for the three months ended June 30, 2020 compared to $79 million for the same period of 2019, primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods. Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 workforce reduction and reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic in the second quarter of 2020 partially offset by additional compensation expense related to the modification of our 2020 variable compensation programs in May 2020. See Part I, Item 1 – Financial Statements, Note 15 Compensation Plans for more information.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $33 million to $88 million in the second quarter of 2020 compared to $121 million in 2019 was predominately due to a decrease in our depletable basis as a result of our asset impairment recorded in the first quarter of 2020.

Other expenses, net — The increase in other expenses of $12 million to $67 million for the three months ended June 30, 2020 compared to $55 million for the same period of 2019 was largely the result of a one-time payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract partially offset by a decrease in natural gas trading purchases.

Interest and debt expense, net — Interest and debt expense, net decreased $13 million to $85 million in the second quarter of 2020 compared to $98 million in the same period of 2019 due to the repayment of the 2020 Senior Notes in January 2020, the 2019 repurchases of our Second Lien Notes and lower variable interest rates on our borrowings under the 2016 Credit Agreement and 2017 Credit Agreement.

Net gain on early extinguishment of debt — We did not have a net gain on early extinguishment of debt for the three months ended June 30, 2020, which is a decrease of $20 million from the same period in 2019. The decrease was due to a lack of open market purchases in the second quarter of 2020.

Other non-operating expense — Other non-operating expense increased $44 million to $47 million for the three months ended June 30, 2020 compared to $3 million in the same period for 2019. The increase was primarily a result of professional fees and costs associated with the preparation of the Chapter 11 Cases.

Six months ended June 30, 2020 vs 2019

Oil and natural gas sales — Oil and natural gas sales decreased 43%, or $504 million, for the six months ended June 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:


	Oil		NGLs		Natural Gas		Total
	(in millions)
Six months ended June 30, 2019	$	976	$	98	$	105	$	1,179
Changes in realized prices	(371)		(27)		(33)		(431)
Changes in production	(56)		(9)		(8)		(73)
Six months ended June 30, 2020	$	549	$	62	$	64	$	675

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. Net proceeds from settled hedges were $40 million for the six months ended June 30, 2020, excluding the effect of our derivative contracts sold prior to maturity in the first quarter of 2020, compared to net proceeds of $28 million for the same period of 2019, which had a positive impact of $12 million on our total revenue between periods. Including the effect of settled hedges and proceeds from derivative contracts sold in the first quarter of 2020, our oil and natural gas revenue decreased by $429 million or 36% compared to the same prior-year period.

Net derivative gain (loss) from commodity contracts — Net derivative gain from commodity contracts was $75 million for the six months ended June 30, 2020 compared to a loss of $68 million in the same period of 2019, representing an overall change of $143 million as reflected in the following table. 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, volatility, time to expiration and the associated forward curves.


	Six months ended June 30,
	2020		2019
	(in millions)
Non-cash derivative (loss) gain, excluding noncontrolling interest	$	(35)	$	(93)
Non-cash derivative gain (loss), noncontrolling interest	7		(3)
Total non-cash changes	(28)		(96)
Net proceeds on settled commodity derivatives	40		28
Net proceeds on derivative sales prior to maturity	63		—
Net derivative gain (loss)	$	75	$	(68)

Other revenue — The decrease in other revenue of $133 million to $99 million for the six months ended June 30, 2020 compared to $232 million in the same period of 2019 was due to lower natural gas trading activity and lower electricity sales due to a planned major maintenance at the Elk Hills power plant in 2020.

Production costs — Production costs for the six months ended June 30, 2020 decreased $144 million to $319 million compared to $463 million for the same period of 2019, resulting in a 31% decrease. The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our October 2019 workforce reduction and reduced work schedules during the months of April and May 2020. The operating costs of shut in wells, as well as lower activity levels in response to the current environment, such as downhole maintenance, also contributed to the decrease.

General and administrative expenses — Our general and administrative (G&A) expenses decreased $33 million to $129 million for the six months ended June 30, 2020 compared to $162 million for the same period of 2019, primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods. Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 workforce reduction and reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic in the second quarter of 2020 partially offset by an increase in compensation expense due to changes to our 2020 compensation program.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $32 million to $207 million in the first half of 2020 compared to $239 million in 2019 was predominately due to the asset impairment recorded in the first quarter of 2020.

Asset impairments — In the first quarter of 2020, we recorded an impairment charge of $1.7 billion, of which $1.5 billion related to certain of our proved properties and $228 million related to unproved acreage that we no longer intend to pursue. No asset impairments were recorded in the second quarter of 2020. For further detail about the asset impairment, see Part I, Item 1 – Financial Statements, Note 14 Asset Impairments.

Other expenses, net — The decrease in other expenses of $67 million to $136 million for the six months ended June 30, 2020 compared to $203 million for the same period of 2019 was largely the result of lower natural gas trading activity, partially offset by a one-time deficiency payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract.

Interest and debt expense, net — Interest and debt expense, net decreased $26 million to $172 million in the first half of 2020 compared to $198 million in the same period of 2019 due to the repayment of the 2020 Senior Notes in January 2020, reduction in the outstanding balance of the Second Lien Notes due to open market purchases and a reduction in the interest rates in our 2016 Credit Agreement and 2017 Credit Agreement.

Net gain on early extinguishment of debt — The net gain on early extinguishment of debt for the six months ended June 30, 2020 was $5 million, which is a decrease of $21 million from $26 million during the same period in 2019. The decrease was due to lower debt repurchase activity in 2020.

Other non-operating expense — Other non-operating expense increased $51 million to $61 million for the six months ended June 30, 2020 compared to $10 million in the same period for 2019. The increase was primarily a result of professional fees and costs associated with the preparation of the Chapter 11 Cases.

Stock-Based Compensation

Our consolidated results of operations for the three and six months ended June 30, 2020 and 2019 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include stock options, restricted stock units and performance stock units that either cliff vest at the end of a three-year period or vest ratably over a three-year period, some of which are partially settled in cash. Our equity-settled awards granted to non-employee directors are stock grants that vest immediately or restricted stock units that cliff vest after one year. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

Changes in our stock price introduce volatility in our results of operations because we pay cash-settled awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Cash-settled awards, including executive awards partially settled in cash, account for approximately 40% of our total outstanding awards. Our obligations for equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation is included in both general and administrative (G&A) expense and production costs as shown in the table below:


	Three months ended June 30,										Six months ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in millions, except per Boe amounts)
G&A expense
Cash-settled awards	$	—	$	3	$	(3)	$	(2)	$	13	$	(15)
Equity-settled awards	1		4		(3)		4		7		(3)
Total in G&A	$	1	$	7	$	(6)	$	2	$	20	$	(18)
Total in G&A per Boe	$	0.10	$	0.60	$	(0.50)	$	0.10	$	0.84	$	(0.74)

Production costs
Cash-settled awards	$	—	$	1	$	(1)	$	(1)	$	4	$	(5)
Equity-settled awards	—		1		(1)		—		2		(2)
Total in production costs	$	—	$	2	$	(2)	$	(1)	$	6	$	(7)
Total in production costs per Boe	$	—	$	0.17	$	(0.17)	$	(0.05)	$	0.25	$	(0.30)

Total stock-based compensation expense	$	1	$	9	$	(8)	$	1	$	26	$	(25)
Total stock-based compensation expense per Boe	$	0.10	$	0.77	$	(0.67)	$	0.05	$	1.09	$	(1.04)

Changes to the 2020 Compensation Program

Non-GAAP Financial Measures

Adjusted net (loss) income — Our results of operations, which are presented in accordance with U.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) that excludes those items. This measure is not meant to disassociate these items from management's performance but rather is meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted net (loss) income and presents the GAAP financial measure of net (loss) income attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net (loss) income per diluted share:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(in millions, except share data)
Net (loss) income	$	(247)	$	41	$	(1,992)	$	(3)
Net income attributable to noncontrolling interests	(24)		(29)		(75)		(52)
Net (loss) income attributable to common stock	(271)		12		(2,067)		(55)
Unusual, infrequent and other items:
Asset impairment	—		—		1,736		—
Non-cash derivative (loss) gain from commodities, excluding noncontrolling interest	—		(4)		35		93

Severance costs	—		2		—		2
Incentive and retention award modification	4		—		4		—
Net gain on early extinguishment of debt	—		(20)		(5)		(26)

Professional fees and costs related to our Chapter 11 Cases	42		—		49		—
Deficiency payment on a pipeline delivery contract	20		—		20		—
Other, net	3		(4)		18		3
Total unusual, infrequent and other items	69		(26)		1,857		72
Adjusted net (loss) income	$	(202)	$	(14)	$	(210)	$	17

Net (loss) income attributable to common stock per diluted share	$	(5.47)	$	0.24	$	(41.84)	$	(1.13)
Adjusted net (loss) income per diluted share	$	(4.08)	$	(0.29)	$	(4.25)	$	0.35

Adjusted EBITDAX — We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. A version of adjusted EBITDAX is a material component of certain of our financial covenants under our 2014 Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted EBITDAX:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(in millions)
Net (loss) income	$	(247)	$	41	$	(1,992)	$	(3)
Interest and debt expense, net	85		98		172		198
Depreciation, depletion and amortization	88		121		207		239
Exploration expense	2		10		7		20
Unusual, infrequent and other items	69		(26)		1,857		72
Other non-cash items	22		11		19		30
Adjusted EBITDAX	$	19	$	255	$	270	$	556

The following table sets forth a reconciliation of the GAAP measure of net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX:


	Six months ended June 30,
	2020		2019
	(in millions)
Net cash provided by operating activities	$	93	$	272
Cash interest	59		225
Exploration expenditures	7		10
Working capital changes	111		49

Adjusted EBITDAX	$	270	$	556

Adjusted G&A — Management uses a measure called adjusted general and administrative (adjusted G&A) expense to provide useful information to investors interested in comparing our costs between periods and performance to our peers. We define adjusted G&A expenses as general and administrative expenses excluding severance and other non-recurring costs.

The following table presents the reconciliation of our consolidated general and administrative expenses to the non-GAAP measure of adjusted G&A:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(in millions)						(in millions)
General and administrative expenses	$	69	$	79	$	129	$	162
Incentive and retention award modification	(4)		—		(4)		—
Severance costs	—		(1)		—		(1)
Office consolidation	—		(1)		—		(1)
Adjusted G&A	$	65	$	77	$	125	$	160

Liquidity and Capital Resources

Cash Flow Analysis


	Six months ended June 30,
	2020		2019
	(in millions)
Cash flow from operating activities	$	93	$	272
Cash flow from investing activities:
Capital investments	$	(33)	$	(271)
Changes in capital investment accruals	$	(28)	$	(57)
Acquisitions, divestitures and other	$	34	$	158
Cash flow from financing activities:
Net debt transactions	$	110	$	(74)
Net distributions to noncontrolling interest holders	$	(66)	$	(16)
Issuance of common stock and other	$	(1)	$	(2)

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 66%, or $179 million, to $93 million for the six months ended June 30, 2020 from $272 million in the same period of 2019. Changes in operating assets and liabilities, net in the six months ended June 30, 2020 increased our operating cash flow by $130 million compared to a reduction of $52 million in the comparable six months of 2019. This positive change primarily resulted from a decrease in accounts receivable due to lower commodity prices between periods partially offset by lower trade payables as a result of our reduced capital plan and cost saving initiatives. Operating cash flow in the first six months of 2020 also reflected the positive contribution of the $63 million of proceeds from the early settlement of derivative contracts.

Cash flows from investing activities — Our net cash used in investing activities of $27 million for the six months ended June 30, 2020 primarily reflected $33 million of capital investments (excluding $28 million in capital-related accrual changes). Investing activities also included proceeds of $41 million related to a sale of royalty interests and a non-core asset in the first half of 2020. For the six months ended June 30, 2019, our net cash used in investing activities of $170 million primarily included approximately $271 million of capital investments (excluding $57 million in capital-related accrual changes), of which $43 million was funded by BSP, partially offset by $165 million of proceeds related to our Lost Hills sale.

Cash flows from financing activities — Our net cash provided by financing activities of $43 million for the six months ended June 30, 2020 primarily included $213 million in net proceeds on our 2014 Revolving Credit Facility partially offset by $100 million for the repayment of the 2020 Senior Notes at maturity, $68 million of distributions to our noncontrolling interest holders and $3 million for debt repurchases of our Second Lien Notes. We also had an additional $2 million in contributions from a noncontrolling interest holder. For the six months ended June 30, 2019, our net cash used in financing activities of $92 million was primarily comprised of $59 million used for debt repurchases of our Senior Notes, $65 million of distributions paid to our non-controlling interest holders, and $15 million of net repayments on our 2014 Revolving Credit Facility partially offset by $49 million in a net contribution from a noncontrolling interest holder.

Liquidity

Our spin–off from Occidental on November 30, 2014 burdened us with significant debt which was used to pay a $6.0 billion cash dividend to Occidental. Together with the activity level and payables that we assumed from Occidental and due to Occidental's retention of the vast majority of our receivables, our debt peaked at approximately $6.8 billion in May 2015. Since then, we have engaged in a series of assets sales, joint ventures, debt exchanges, tenders and repurchases and other financing transactions to reduce our overall debt and improve our balance sheet. As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021.

The commencement of the Chapter 11 Cases constituted an immediate event of default that automatically accelerated our obligations under the 2014 Revolving Credit Facility and our other debt agreements. Any efforts to enforce payment obligations related to the acceleration of our obligations under these debt agreements were automatically stayed immediately upon filing the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

As of June 30, 2020, we had available cash of $105 million and no ability to borrow under our 2014 Revolving Credit Facility due to the missed interest payments and forbearance described below. As of June 30, 2020 and December 31, 2019, we had letters of credit outstanding of $152 million and $165 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

For more information on our debt, see Part I, Item 1 – Financial Statements, Note 5 Debt and for more information on the Chapter 11 Cases, see Part I, Item 1 – Financial Statements, Note 1 Basis of Presentation.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into the Senior DIP Credit Agreement which provides for a Senior DIP Facility in an aggregate principal amount of up to approximately $483 million. The Senior DIP Facility includes a $250 million revolving facility which will be primarily used by us to (i) fund working capital needs and capital expenditures and additional letters of credit during the pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Senior DIP Facility. Until the Bankruptcy Court enters a final order with respect to our DIP credit agreements, only $85 million of revolving borrowings are available. If the Bankruptcy Court enters a final order approving the Senior DIP Facility in its current form following a hearing on August 14, 2020, we expect the full remaining amount of the $250 million revolving facility to become available. The Senior DIP Facility also includes (a) a $150 million letter of credit facility which was used to deem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (b) $83 million of term loans borrowings which were used to repay a portion of the 2014 Revolving Credit Facility.

On July 23, 2020, we also entered into a Junior DIP Credit Agreement which provides for a Junior DIP Facility in an aggregate principal amount of $650 million. The proceeds of the Junior DIP Facility were used to (i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility.

The Senior DIP Credit Agreement and Junior DIP Credit Agreement include conditions precedent, representations and warranties, affirmative and negative covenants and events of default customary for financings of their type and size. The Senior DIP Facility and the Junior DIP Facility both mature on January 15, 2021. See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our DIP credit agreements.

Missed Interest Payments and Forbearance

On May 15, 2020, we did not make an interest payment of approximately $4 million on our 2024 Notes. The indenture governing our 2024 Notes provides for a 30-day grace period and the payment was subsequently made on June 12, 2020.

On May 29, 2020, we did not pay approximately $51 million in the aggregate interest due under the 2017 Credit Agreement and the 2016 Credit Agreement. Our failure to make those interest payments constituted events of default under the 2017 Credit Agreement, 2016 Credit Agreement and, as a result of cross default, under the 2014 Revolving Credit Facility.

On June 2, 2020, we entered into Forbearance Agreements with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement. Pursuant to the Forbearance Agreements, the lenders who are parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, initially through June 14, 2020 and subsequently through July 15, 2020.

On June 15, 2020, we did not make an interest payment of approximately $72 million on our Second Lien Notes. The indenture governing the Second Lien Notes provides for a 30-day grace period, which expired on July 15, 2020.

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

In early March 2020, in response to the rapid fall in commodity prices, we monetized all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million to enhance our liquidity. As of June 30, 2020, we did not have any commodity hedges covering our share of production.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement. 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 currently have the following Brent-based crude oil contracts:


	August-September 2020		Q4 2020		Q1 2021		Q2 2021		July 2021
Sold Calls:
Barrels per day	4,950		4,800		4,500		4,500		4,200
Weighted-average price per barrel	$	48.05	$	48.05	$	48.05	$	48.05	$	48.05





Purchased Puts:
Barrels per day	9,900		9,600		9,000		9,000		8,400
Weighted-average price per barrel	$	40.00	$	40.00	$	40.00	$	40.00	$	40.00

Sold Puts:
Barrels per day	4,950		4,800		4,500		4,500		4,200
Weighted-average price per barrel	$	30.00	$	30.00	$	30.00	$	30.00	$	30.00

Swaps:
Barrels per day	6,600		6,400		6,000		6,000		5,600
Weighted-average price per barrel	$	44.75	$	44.75	$	44.75	$	44.75	$	44.75

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.

We also currently have Brent-based crude oil contracts for insignificant volumes through May 2021 which were entered into by our BSP JV and are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the BSP JV could affect the timing of the redemption of the BSP preferred interest.

2020 Capital Program

We entered 2020 with an internally funded capital program of $100 million to $300 million. In March 2020, we reduced our capital investment to a level that maintains the mechanical integrity of our facilities to operate in a safe and environmentally responsible manner in response to the collapse in crude oil prices. We made $33 million of internally funded capital investments in the first half of 2020 and expect to invest up to an additional $20 million through the end of 2020. In order to meet this level of investment, we suspended all internally funded drilling and capital workovers for the second quarter and significantly reduced other activities.

Our JV partners invested $98 million in the first half of 2020. On March 27, 2020, Alpine elected to suspend its funding obligations under the Alpine JV. For further information, regarding the Alpine JV and its funding obligations, see the Development Joint Ventures section above.

The amounts in the table below reflect our consolidated capital investment, excluding changes in capital investment accruals, for the six months ended June 30, 2020 and 2019:


	Six months ended June 30,
	2020		2019
	(in millions)
Oil and natural gas	$	32	$	212
Exploration	—		9
Corporate and other	1		7
Total internally funded capital	33		228
BSP funded capital	—		43
Total consolidated capital investment	$	33	$	271

The 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.

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.

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.

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 June 30, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates. 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 accrued would not be material to our consolidated financial position or results of operations.

Significant Accounting and Disclosure Changes

See Part I, Item 1, Note 2 Accounting and Disclosure Changes in the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q 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, including our ability to operate as a going concern

•business prospects

•transactions and projects

•operating costs

•Value Creation Index (VCI) metrics, which are based on certain estimates including future production rates, costs and commodity prices

•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

•ability to pay our creditors

•ability to comply with the covenants in our debt agreements and instruments

•credit ratings

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:

•risks and uncertainties relating to the Chapter 11 Cases filed in the Bankruptcy Court, including our ability to obtain the Bankruptcy Court’s approval with respect to our motions, our ability to develop, confirm and consummate a Chapter 11 plan or an alternative restructuring transaction, risks associated with third-party motions, Bankruptcy Court rulings and the outcome of the Chapter 11 Cases in general, and the length of time we will operate under the Chapter 11 Cases

•the potential adverse effects of disruption from the Chapter 11 Cases on us, our liquidity and/or results of operations, and on the interests of our various constituents making it more difficult to maintain business and operational relationships, retain key executives and maintain various licenses and approvals necessary for us to conduct our business

•our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

•risk and uncertainties relating to our ability to obtain requisite support for our Chapter 11 plan from various stakeholders and confirm and consummate that plan

•increased advisory costs to execute a reorganization

•risks associated with our ability to continue as a going concern

•the impact of the NYSE’s delisting of our common stock on the liquidity and market price of our common stock and on our ability to access the public capital markets;

•risks related to the trading of our securities on the OTC Pink Market

•the volatility of and potential for sustained low oil, natural gas and NGL prices

•commodity price changes, including extended periods of low oil, natural gas or NGL prices

•debt limitations on our financial flexibility

•inability to reach an agreement with our creditors with respect to a restructuring of our debt

•insufficient cash flow to fund planned investments, 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

•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 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

•unexpected geologic conditions

•incorrect estimates of reserves and related future cash flows and the inability to replace reserves

•changes in business strategy

•PSC effects on production and unit production costs

•effect of 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 pandemic

•factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K available at www.crc.com.

Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and six months ended June 30, 2020, there were no material changes to commodity price risk, interest rate risk or counterparty credit risk from the information provided under Item 305 of Regulation S-K included under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A) – Quantitative and Qualitative Disclosures About Market Risk in the 2019 Form 10-K, except as discussed below.

Commodity Price Risk

In March 2020, we monetized crude oil hedge positions in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million. We recognized the proceeds received in net derivative gain (loss) from commodity contracts on our condensed consolidated statements of operations in the first quarter of 2020. As of June 30, 2020, we did not have any commodity hedges covering our share of production.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement. 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.

Our current oil hedge positions provide for the following expected outcomes:

August-September 2020

Q4
2020

Q1
2021

Q2
2021

July 2021

Barrels per day

4,950

4,800

4,500

4,200

Receive Brent if Brent > $40

Receive $40 if Brent between $30 and $40

Receive Brent +$10 if Brent <$30

Barrels per day

4,950

4,800

4,500

4,200

Ceiling price of $48.05 Brent

Receive Brent between $40 and $48.05

Floor price of $40 Brent

Barrels per day

6,600

6,400

6,000

5,600

Receive $44.75 Brent at all prices

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For derivative instruments entered into as part of our hedging program, we are subject to counterparty credit risk to the extent the counterparty is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and continuing to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of June 30, 2020, the substantial majority of the credit exposures related to our business was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at June 30, 2020 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

As of June 30, 2020, we had borrowings of $1.3 billion outstanding under our 2017 Credit Agreement, $1 billion outstanding under our 2016 Credit Agreement and $731 million outstanding under our 2014 Revolving Credit Facility, all of which carry variable interest rates. On July 15, 2020, we filed for relief under Chapter 11 of the Bankruptcy Code and as a result interest on our pre-petition debt is limited to what is determined by the Bankruptcy Court to be an allowed claim. On July 23, 2020, we entered into debtor-in-possession credit agreements, which carry variable interest rates, as further described in Part I, Item 1 – Financial Statements, Note 5 Debt.

In March 2018, we entered into derivative contracts that limit our interest-rate exposure with respect to $1.3 billion of our variable-rate indebtedness. The interest-rate contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR exceeds 2.75% for any monthly period prior to May 4, 2021. We did not report any gains or losses on these contracts for the three months ended June 30, 2020 or the three months ended June 30, 2019 in other non-operating expense on our condensed consolidated statements of operations. No settlement payments were received in either 2020 or 2019.

Item 4 Controls and Procedures

Our President and Chief Executive Officer and our Senior Executive Vice President and Chief Financial Officer supervised and participated in our 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 President and Chief Executive Officer and our Senior Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2020.

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 June 30, 2020 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1Legal Proceedings

On the July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases filed by us are being jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). See Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Business Environment and Industry Outlook, Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code for more information.

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 Form 10-K for the year ended December 31, 2019.

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 Form 10-K for the year ended December 31, 2019. Other than as provided below, there were no material changes to those risk factors during the six months ended June 30, 2020.

We are subject to the risks and uncertainties associated with the Chapter 11 Cases.

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. For the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan, as well as our continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

•our ability to confirm and consummate the plan of reorganization contemplated by the RSA (the RSA Plan), or develop, negotiate, confirm and consummate an alternative plan;

•our ability to obtain court approval with respect to motions filed in the Chapter 11 Cases from time to time;

•our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;

•our ability to maintain contracts that are critical to our operations;

•our ability to execute our business plan;

•the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

•our ability to obtain Bankruptcy Court approval of the various motions and other requests, including with respect to our Senior DIP Credit Agreement and the Junior DIP Credit Agreement (together, the DIP facilities);

•the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization, to appoint a Chapter 11 trustee, or to convert the Chapter 11 Cases to a Chapter 7 proceeding;

•the high costs of bankruptcy proceedings and related fees; and

•the actions and decisions of our creditors and other third parties who have interests in the Chapter 11 Cases that may be inconsistent with our plans.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, prior approval of the Bankruptcy Court is required to enter into transactions outside the ordinary course of business, which may limit our ability to respond to certain events or take advantage of certain opportunities. In addition, certain of our creditors and other stakeholders may bring litigation against us during the course of the Chapter 11 Cases. Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact of events that will occur during the Chapter 11 Cases that may be inconsistent with our plans.

Operating during the Chapter 11 Cases for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operating under Chapter 11 of the Bankruptcy Code and subject to Bankruptcy Court supervision may have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 Cases continue, our senior management may be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Chapter 11 of the Bankruptcy Code also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers may lose confidence in our ability to reorganize our business successfully and may seek to establish alternative commercial relationships.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently reorganized under Chapter 11 of the Bankruptcy Code.

The RSA is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the RSA is terminated, our ability to confirm a plan of reorganization and consummate a restructuring of our debt could be materially and adversely affected.

The RSA sets forth certain conditions we must satisfy during the Chapter 11 Cases, including the timely satisfaction of certain milestones to consummate a plan of reorganization (the RSA Plan). Our ability to timely satisfy such conditions and milestones is subject to risks and uncertainties that are beyond our control. The parties to the RSA may terminate the RSA under certain circumstances, such as our failure to fulfill certain conditions or reach certain milestones. A termination of the RSA may result in, among other things, the loss of support for the RSA Plan, which could adversely affect our ability to confirm and consummate the RSA Plan and our ability to emerge from Chapter 11. If the RSA Plan is not consummated, there can be no assurance that any new plan of reorganization would provide the same treatment to holders of claims or interests as those proposed under the RSA Plan, and our Chapter 11 proceedings may become protracted, which could significantly and detrimentally impact our relationships with regulators, government agencies, vendors, suppliers, employees and major customers.

There can be no assurance that the solicited classes of claims will vote to accept the RSA Plan.

There can be no assurance that the RSA Plan will receive the necessary level of support to be implemented or will be approved by the Bankruptcy Court. The success of the restructuring transactions will depend on the willingness of certain existing creditors to agree to the exchange or modification of their claims and approval by the Bankruptcy Court, and there can be no certainty of success with respect to those matters. Holders of certain claims that are impaired under the RSA Plan are entitled to vote to accept or reject the RSA Plan. Although certain parties are bound to vote for the RSA Plan, if the RSA is terminated they will not be so bound and any vote or consent given by such parties prior to such termination may be revoked.

We may receive objections to the terms of the RSA, including official objections to confirmation of the RSA Plan from the various stakeholders in the Chapter 11 Cases. We cannot predict the impact that any objection or third party motion may have on the Bankruptcy Court’s decision to confirm the RSA Plan or our ability to complete an in-court restructuring as contemplated by the RSA or otherwise. Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.

If we do not receive sufficient support for the RSA Plan, or if the RSA Plan is not confirmed by the Bankruptcy Court, it is unclear what, if any, distributions holders of claims against us may ultimately receive with respect to their claims and interests. There can be no assurance as to whether or when we will emerge from Chapter 11. If no plan of reorganization can be confirmed, or if the Bankruptcy Court otherwise finds that it would be in the best interest of holders of claims and interests, the Chapter 11 Cases may be converted to a case under Chapter 7 of the Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code.

We may not be able to obtain confirmation of the RSA Plan or another Chapter 11 plan of reorganization.

Even if the RSA Plan is approved by the creditors entitled to vote thereon, the Bankruptcy Court, as a court of equity, may exercise substantial discretion and may choose not to confirm the RSA Plan. Section 1129 of the Bankruptcy Code requires, among other things, a showing that confirmation of a plan of reorganization will not be followed by liquidation or the need for further financial reorganization, and that the value of distributions to dissenting holders of claims and interests will not be less than the value such holders would receive if we liquidated under Chapter 7. Although we believe that the RSA Plan will satisfy such tests, there can be no assurance that the Bankruptcy Court will reach the same conclusion.

Confirmation of the RSA Plan will also be subject to certain conditions. These conditions may not be met and there can be no assurance that a sufficient number of creditors will agree to modify or waive such conditions to the extent required by the RSA or RSA Plan, as applicable. Further, changed circumstances may necessitate changes to the RSA Plan. Any such modifications may result in less favorable treatment than the treatment currently anticipated to be included in the RSA Plan based upon the agreed terms of the RSA. Such less favorable treatment may include a distribution of property (including the new common stock that would be issued upon our emergence from bankruptcy) to the class affected by the modification of a lesser value than currently anticipated to be included in the RSA Plan or no distribution of property whatsoever under the RSA Plan. Changes to the RSA Plan may also delay the confirmation of the RSA Plan and our emergence from bankruptcy, which could result in, among other things, increased costs and expenses to the estates of the debtors and could prevent us from exercising our right to acquire ECR’s equity interests in the Ares JV. The conversion right granted to us under the Ares JV Settlement Agreement is only exercisable by us prior to December 31, 2021, and subject to confirmation of the RSA Plan and certain other conditions described in the Settlement Agreement. If these conditions are not met, we will not be able to exercise the conversion right and ECR will continue as our partner in the Ares JV.

The RSA Plan or other plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution. Even if the RSA Plan or other plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.

The RSA or other plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our business and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, the RSA Plan or other plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts may not be accurate. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure, (ii) our ability to obtain adequate liquidity and financing sources, (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial markets and oil and gas industry, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our business. Consequently, there can be no assurance that the results or developments contemplated by the RSA Plan or any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our business or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of the RSA Plan or plan of reorganization.

Even if the RSA Plan or other plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in market demand and increasing expenses. Accordingly, we cannot provide any assurance that the RSA Plan or other plan of reorganization will achieve our stated goals.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if the RSA Plan or other plan of reorganization is confirmed.

We may have insufficient liquidity for our business operations during the Chapter 11 Cases.

Although we have been able to lower our cost structure and create efficiencies, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout the Chapter 11 Cases. Although we believe that we will have sufficient liquidity to operate our business during the pendency of the Chapter 11 Cases, there can be no assurance that the cash made available to us under the DIP facilities or otherwise in our restructuring process and revenue generated by our business operations will be sufficient to fund our operations. In the event that revenue flows and other available cash are not sufficient to meet our liquidity requirements, we may be required to seek additional financing. There can be no assurance that such additional financing would be available or, if available, offered on terms that are acceptable.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of the DIP facilities, (ii) our ability to comply with the terms and conditions of any order governing the use of our cash collateral that may be entered by the Bankruptcy Court in connection with the Chapter 11 Cases, (iii) our ability to maintain adequate cash on hand, (iv) our ability to generate cash flow from operations, (v) our ability to develop, confirm and consummate a plan of reorganization or other alternative restructuring transaction, and (vi) the cost, duration and outcome of the Chapter 11 Cases.

Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing beyond the DIP facilities. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our evaluation of strategic alternatives and preparation for the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout the Chapter 11 Cases. We cannot assure you that cash on hand, cash flow from operations, the DIP facilities and any financing we are able to obtain in connection with our emergence from the Chapter 11 Cases will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases until we emerge from the Chapter 11 Cases.

We may be unable to comply with restrictions or with budget, liquidity, or other covenants imposed by the agreements governing the DIP facilities. Such non-compliance could result in an event of default under the terms of the DIP facilities that, if not cured or waived, may have a material adverse effect on our business, financial condition and results of operations.

The DIP facilities require that we comply with general affirmative and negative covenants such as prohibiting us from incurring or permitting debt, investments, liens or dispositions unless specifically permitted. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply, or obtain a waiver in the event we cannot comply with a covenant, may result in an event of default under the DIP facilities and permit the lenders thereunder to accelerate the loans and otherwise exercise remedies allowable by the agreements governing the DIP facilities.

As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.

During the pendency of the Chapter 11 Cases, we expect our financial results to continue to be volatile and restructuring activities and expenses, claims assessments and continued commodity price volatility to significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing. In addition, if we emerge from the Chapter 11 Cases, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which may have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through the plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis. Certain claims against the debtor arising after July 15, 2020 may be entitled to priority under the Bankruptcy Code along with other claims which may not be subject to discharge by the Bankruptcy Court. These claims may have an adverse effect on our results of operations and cash flow.

The pursuit of the restructuring transactions under the RSA will consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

Although the RSA and RSA Plan are designed to minimize the length of our Chapter 11 proceedings, it is impossible to predict with certainty the amount of time and resources necessary to successfully implement the restructuring transactions contemplated by the RSA. Compliance with the terms of the RSA will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proposed transactions. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 proceedings are protracted.

As a result of the Chapter 11 Cases, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of our employee morale could adversely affect our business and results of operations.

The implementation of a plan of reorganization is expected to reduce or eliminate our federal and state income tax net operating loss carryforwards and may impair our ability to utilize any remaining net operating loss carryforwards and certain other tax attributes during the current year and in future years. Moreover, subsequent transfers of our equity, or issuances of equity, may further impair our ability to utilize our tax attributes.

Under U.S. federal income tax law, a corporation is generally permitted to offset net taxable income in a given year with net operating losses (NOLs) carried forward from prior years. As of December 31, 2019, we had U.S. federal NOL carryforwards and California NOL carryforwards of approximately $1 billion and $2 billion, respectively. In connection with the restructuring process, our NOL carryforwards and certain other tax attributes are expected to be reduced by the amount of discharge of indebtedness we recognize upon the implementation of a plan of reorganization under Section 108 of the Internal Revenue Code of 1986, as amended (the Code). Further, our ability to utilize any remaining NOL carryforwards to offset future taxable income and to reduce U.S. federal and state income tax liabilities is subject to certain requirements and restrictions. If we experience an "ownership change" during or in connection with the restructuring process, as defined in Section 382 of the Code, then our ability to use our NOL carryforwards and certain other tax attributes may also be impaired.

A corporation generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. Under Section 382 and Section 383 of the Code, absent an applicable exception, if a corporation undergoes an ownership change, the amount of its NOLs and other tax attributes that may be used to reduce future U.S. federal and state income tax obligations generally is subject to an annual limitation.

The Bankruptcy Court approved restrictions on certain transfers of our stock to limit the risk of an ownership change prior to our emergence from the Chapter 11 Cases. However, we anticipate that the implementation of a plan of reorganization will result in an ownership change and our ability to utilize our NOL carryforwards and certain other tax attributes may be materially restricted by the resulting annual limitation.

Although an exception to the imposition of an annual limitation can apply in certain Chapter 11 cases under Section 382(l)(5) of the Code, it is currently unknown if a plan of reorganization, once implemented, will meet the requirements of such section or if we will elect out of the application of such section. Moreover, if we apply Section 382(l)(5) of the Code and experience a subsequent ownership change within two years, any remaining net operating losses and certain other tax attributes may be subject to further and more severe limitations.

We have concluded there is substantial doubt about our ability to continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases. There can be no assurance that we will be able to successfully restructure our indebtedness and any restructuring could result in holders of certain liabilities and/or securities, including our common stock, receiving no distributions on account of their claims or interests.

Our significant indebtedness, the unprecedented impact to our financial position resulting from the sharp decrease in commodity prices as a result of the COVID-19 pandemic and the actions of foreign producers, and the continued challenging conditions in the credit and capital markets raise substantial doubt regarding our ability to continue as a going concern. As of June 30, 2020, we had approximately $5.1 billion of debt outstanding, and we had cash on hand of approximately $126 million, of which $21 million was restricted.

We believe the Chapter 11 Cases provide the most expeditious manner in which to deleverage our current capital structure. However, the outcome of the Chapter 11 Cases is subject to uncertainty and is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. There can be no assurance that we will be able to reorganize our capital structure on the terms set forth in the RSA or on other terms acceptable to us, our creditors or other stakeholders, or at all.

Priorities among various constituencies of creditors are dictated by the Bankruptcy Code. Unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a plan of reorganization. The RSA Plan, if approved, will result in holders of common stock receiving no distribution on account of their claims or interests. However, the ultimate recovery to creditors and/or stockholders, if any, will not be determined until the Bankruptcy Court confirms a plan of reorganization. No assurance can be given that the Bankruptcy Court will approve the RSA Plan or what values, if any, will be ascribed to each of our securities or what type or amounts of distributions, if any, our various stakeholders would receive in any restructuring.

Our common stock is quoted on the OTC Pink Market, and thus may have a limited market and lack of liquidity.

Effective July 17, 2020, our common stock began to be quoted on the OTC Pink Market under the ticker symbol "CRCQQ", which may have an unfavorable impact on our stock price and liquidity. The OTC Pink Marketplace is a significantly more limited market than the New York Stock Exchange or the Nasdaq Stock Market. There is no guarantee that active trading in our common stock will develop on the OTC Pink Market. The quotation of our shares on such marketplace may result in a less liquid market available for existing and potential stockholders to trade.

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 Current Report on Form 8-K filed June 3, 2016 and incorporated herein by reference).

3.2			Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed November 10, 2015 and incorporated herein by reference).

10.1			Second Amendment to Forbearance Agreement, dated as of June 30, 2020, by and among the Company, the subsidiary guarantors party thereto, certain Lenders identified therein, JPMorgan Chase Bank, N.A., as Administrative Agent, a Lender and a Letter of Credit Issuer, and Bank of America, N.A., a Lender and a Letter of Credit Issuer (filed as Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed J uly 2 , 2020 and incorporated herein by reference).

10.2			Second Amendment to Forbearance Agreement, dated as of June 30, 2020, by and among the Company, as the Borrower, the subsidiary guarantors party thereto, the various Lenders identified therein and The Bank of New York Mellon Trust Company, N.A., as Administrative Agent (filed as Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed July 2 , 2020 and incorporated herein by reference).

10.3			Second Amendment to Forbearance Agreement, dated as of June 30, 2020, by and among the Company, as the Borrower, the subsidiary guarantors party thereto, the various Lenders identified therein and The Bank of New York Mellon Trust Company, N.A., as Administrative Agent (filed as Exhibit 10.3 to Registrant's Current Report on Form 8-K filed Ju ly 2 , 2020 and incorporated herein by reference).

10.4			Restructuring Support Agreement, dated as of July 15, 2020, by and among the Company and the other parties named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 16, 2020).

10.5			Senior Secured Superpriority Debtor-in-Possession Revolving Credit Facility Commitment Letter, dated as of July 15, 2020, by and among California Resources Corporation, certain of its subsidiaries and JPMorgan Chase Bank, N.A. (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed July 16, 2020).

10.6			Settlement and Assumption Agreement, dated as of July 15, 2020, by and among the Company, California Resources Elk Hills, LLC, Elk Hills Power, LLC, ECR Corporate Holdings GP LLC, ECR I, L.P., SSF IV Energy I AIV 1, L.P., SSF IV Energy I AIV 2, L.P., AEOF ECR Holdings, L.P., and ECR Corporate Holdings, L.P. (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed July 16, 2020).

10.7			Backstop Commitment Agreement, dated as of July 15, 2020, among California Resources Corporation and the Backstop Parties hereto (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 1 7 , 2020).

10.8			Senior Secured Superpriority Debtor-in-Possession Credit Agreement dated as of July 23, 2020, among California Resources Corporation, as the Borrower, the several lenders from time to time parties hereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and as Sole Lead Arranger and Bookrunner (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 24, 2020).

10.9			Junior Secured Superpriority Debtor-in-Possession Credit Agreement dated as of July 2 3 , 2020, among California Resources Corporation, as the Borrower, the several lenders from time to time parties hereto, and Alter Domus Products Corp., as Administrative Agent (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed July 2 4 , 2020).

10.10			Amended and Restated Restructuring Support Agreement, dated as of July 24, 2020, by and among California Resources Corporation, certain of its subsidiaries and the Consenting Parties (as defined therein) (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed July 2 4 , 2020).

10.11			Amended and Restated Backstop Commitment Agreement, dated as of July 24, 2020, by and among California Resources Corporation, certain of its subsidiaries and the Backstop Parties (as defined therein) (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed July 2 4 , 2020).











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:	August 6, 2020	/s/ Roy M. Pineci
		Roy M. Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)