Document

10-Q 1 a2019q110-qdocument.htm 10-Q Document

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019

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

27200 Tourney Road, Suite 315 Santa Clarita, California (Address of principal executive offices)		91355 (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

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. þ 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). þ 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	þ	Accelerated Filer	o	Non-Accelerated Filer	o
Smaller Reporting Company	o	Emerging Growth Company	o

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 þ No

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



Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	CRC	New York Stock Exchange



Shares of common stock outstanding as of March 31, 2019	48,800,217

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	4
	Condensed Consolidated Statements of Cash Flows	5
	Condensed Consolidated Statements of Equity	6
	Notes to the Condensed Consolidated Financial Statements	7
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	General	18
	Business Environment and Industry Outlook	18
	Seasonality	20
	Joint Ventures	20
	Asset Divestiture	20
	Operations	19
	Fixed and Variable Costs	19
	Production and Prices	21
	Balance Sheet Analysis	22
	Statements of Operations Analysis	23
	Liquidity and Capital Resources	28
	2019 Capital Program	31
	Lawsuits, Claims, Commitments and Contingencies	31
	Significant Accounting and Disclosure Changes	31
	Forward-Looking Statements	32
Item 3	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4	Controls and Procedures	33

Part II
Item 1	Legal Proceedings	34
Item 1A	Risk Factors	34
Item 5	Other Disclosures	34
Item 6	Exhibits	35

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of March 31, 2019 and December 31, 2018

(in millions, except share data)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash	$	43		$	17
Trade receivables	296			299
Inventories	71			69
Other current assets, net	167			255
Total current assets	577			640
PROPERTY, PLANT AND EQUIPMENT	22,734			22,523
Accumulated depreciation, depletion and amortization	(16,186		)	(16,068		)
Total property, plant and equipment, net	6,548			6,455
OTHER ASSETS	105			63
TOTAL ASSETS	$	7,230		$	7,158



CURRENT LIABILITIES
Current maturities of long-term debt	100			—
Accounts payable	304			390
Accrued liabilities	285			217
Total current liabilities	689			607
LONG-TERM DEBT	5,169			5,251
DEFERRED GAIN AND ISSUANCE COSTS, NET	203			216
OTHER LONG-TERM LIABILITIES	692			575
MEZZANINE EQUITY
Redeemable noncontrolling interests	766			756
EQUITY
Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at March 31, 2019 and December 31, 2018	—			—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (March 31, 2019 - 48,800,217 and December 31, 2018 - 48,650,420)	—			—
Additional paid-in capital	4,989			4,987
Accumulated deficit	(5,409		)	(5,342		)
Accumulated other comprehensive loss	(6		)	(6		)
Total equity attributable to common stock	(426		)	(361		)
Equity attributable to noncontrolling interests	137			114
Total equity	(289		)	(247		)
TOTAL LIABILITIES AND EQUITY	$	7,230		$	7,158

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three months ended March 31, 2019 and 2018

(in millions, except share data)



	Three months ended March 31,
	2019			2018
REVENUES AND OTHER
Oil and gas sales	$	601		$	575
Net derivative loss from commodity contracts	(89		)	(38		)
Other revenue	178			72
Total revenues and other	690			609

COSTS AND OTHER
Production costs	233			212
General and administrative expenses	83			63
Depreciation, depletion and amortization	118			119
Taxes other than on income	41			38
Exploration expense	10			8
Other expenses, net	148			61
Total costs and other	633			501
OPERATING INCOME	57			108

NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(100		)	(92		)
Net gain on early extinguishment of debt	6			—
Other non-operating expenses	(7		)	(7		)
(LOSS) INCOME BEFORE INCOME TAXES	(44		)	9
Income tax	—			—
NET (LOSS) INCOME	(44		)	9
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
Mezzanine equity	(28		)	(14		)
Equity	5			3
Net (income) loss attributable to noncontrolling interests	(23		)	(11		)
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(67	)	$	(2	)

Net loss attributable to common stock per share
Basic	$	(1.38	)	$	(0.05	)
Diluted	$	(1.38	)	$	(0.05	)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income

For the three months ended March 31, 2019 and 2018

(in millions)



	Three months ended March 31,
	2019			2018
Net (loss) income	$	(44	)	$	9
Net income attributable to noncontrolling interests	(23		)	(11		)
Other comprehensive income items:
Reclassification of realized losses on pension and postretirement benefits to income^(a)	—			2
Comprehensive loss attributable to common stock	$	(67	)	$	—


(a)	No associated tax for the three months ended March 31, 2019 and 2018. 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 Cash Flows

For the three months ended March 31, 2019 and 2018

(in millions)



	Three months ended March 31,
	2019			2018
CASH FLOW FROM OPERATING ACTIVITIES
Net (loss) income	$	(44	)	$	9
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	118			119
Net derivative loss from commodity contracts	89			38
Net proceeds (payments) on settled commodity derivatives	14			(31		)
Net gain on early extinguishment of debt	(6		)	—
Amortization of deferred gain	(18		)	(19		)
Dry hole expenses	3			2
Other non-cash charges to income, net	26			14
Changes in operating assets and liabilities, net	(24		)	68
Net cash provided by operating activities	158			200

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(131		)	(139		)
Changes in capital investment accruals	(47		)	5
Acquisitions	(2		)	(3		)
Other	(2		)	(1		)
Net cash used in investing activities	(182		)	(138		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from 2014 Revolving Credit Facility	615			81
Repayments of 2014 Revolving Credit Facility	(579		)	(444		)
Debt repurchases	(14		)	(2		)
Contributions from noncontrolling interest holders, net	49			747
Distributions paid to noncontrolling interest holders	(20		)	(18		)
Issuance of common stock	—			50
Shares canceled for taxes	(1		)	(2		)
Net cash provided by financing activities	50			412
Increase in cash	26			474
Cash—beginning of period	17			20
Cash—end of period	$	43		$	494

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity

For the three months ended March 31, 2019 and 2018

(in millions)



	Additional Paid-in Capital		Accumulated (Deficit) Earnings			Accumulated Other Comprehensive (Loss) Income			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	—		(67		)	—			(67		)	(5		)	(72		)
Contribution from noncontrolling interest holders, net	—		—			—			—			49			49
Distributions to noncontrolling interest holders	—		—			—			—			(21		)	(21		)
Issuance of common stock	—		—			—			—			—			—
Other comprehensive income	—		—			—			—			—			—
Share-based compensation, net	2		—			—			2			—			2
Balance, March 31, 2019	$	4,989	$	(5,409	)	$	(6	)	$	(426	)	$	137		$	(289	)

Balance, December 31, 2017	$	4,879	$	(5,670	)	$	(23	)	$	(814	)	$	94		$	(720	)
Net loss	—		(2		)	—			(2		)	(3		)	(5		)
Contribution from noncontrolling interest holders, net	—		—			—			—			33			33
Distributions to noncontrolling interest holders	—		—			—			—			(15		)	(15		)
Issuance of common stock	50		—			—			50			—			50
Other comprehensive income	—		—			2			2			—			2
Share-based compensation, net	1		—			—			1			—			1
Balance, March 31, 2018	$	4,930	$	(5,672	)	$	(21	)	$	(763	)	$	109		$	(654	)


Note:	The above table excludes amounts related to redeemable noncontrolling interests recorded 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

Notes to the Condensed Consolidated Financial Statements

March 31, 2019

NOTE 1 THE SPIN-OFF AND BASIS OF PRESENTATION

The Separation and Spin-off

We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We were incorporated in Delaware as a wholly owned subsidiary of Occidental Petroleum Corporation (Occidental) on April 23, 2014, and we became an independent, 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.

Basis of Presentation

In the opinion of our management, the accompanying financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our financial position as of March 31, 2019 and December 31, 2018 and the statements of operations, comprehensive income, cash flows and equity for the three months ended March 31, 2019 and 2018, as applicable. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and 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 pursuant to the rules and regulations of the United States (U.S.) Securities and Exchange Commission (SEC) 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 consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2018.


NOTE 2	ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

We adopted the Financial Accounting Standards Board's new lease accounting rules (ASC 842), as of January 1, 2019, using the modified retrospective approach where the new lease standard is not applied to prior comparative periods, which continue to be presented under accounting standards in effect for those prior periods. Under the modified retrospective approach, we recognized right-of-use assets and lease liabilities of approximately $66 million as of the adoption date. The adoption of the new lease accounting rules did not materially impact our consolidated net earnings and had no impact on cash flows or beginning retained earnings. The new lease standard does not affect our liquidity and has no impact on our debt-covenant calculations under our 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement. See Note 12 Leases for more information.


NOTE 3	OTHER INFORMATION

Cash at March 31, 2019 and December 31, 2018 included approximately $26 million and $2 million, respectively, that is restricted for capital investments and distributions to a joint venture (JV) partner.

Other current assets, net as of March 31, 2019 and December 31, 2018 consisted of the following:



	March 31,		December 31,
	2019		2018
	(in millions)
Derivative assets	$	79	$	168
Amounts due from joint interest partners	68		68
Prepaid expenses	20		16
Other	—		3
Other current assets, net	$	167	$	255

Accrued liabilities as of March 31, 2019 and December 31, 2018 consisted of the following:



	March 31,		December 31,
	2019		2018
	(in millions)
Accrued employee-related costs	$	69	$	109
Accrued interest	56		15
Accrued taxes other than on income	51		38
Asset retirement obligation	32		31
Operating lease liability	27		—
Accrued distribution to JV partner	19		—
Other	31		24
Accrued liabilities	$	285	$	217

Other long-term liabilities included asset retirement obligations (ARO) of $490 million and $402 million at March 31, 2019 and December 31, 2018, respectively. As of March 31, 2019, the timing of our cash flows and additional testing costs associated with our future retirement activities were adjusted as a result of the enactment of new regulations, which resulted in an $87 million increase in the aggregate amount of our ARO. The Office of Administrative Law approved the Division of Oil, Gas, and Geothermal Resources' idle well management regulations on March 20, 2019, with an effective date of April 1, 2019.

Fair Value of Financial Instruments

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

Supplemental Cash Flow Information

We did not make U.S. federal and state income tax payments during the three months ended March 31, 2019 and 2018. Interest paid, net of capitalized amounts, totaled approximately $69 million and $60 million for the three months ended March 31, 2019 and 2018, respectively.

NOTE 4 INVENTORIES

Inventories as of March 31, 2019 and December 31, 2018 consisted of the following:



	March 31,		December 31,
	2019		2018
	(in millions)
Materials and supplies	$	68	$	65
Finished goods	3		4
Total	$	71	$	69

NOTE 5 DEBT

As of March 31, 2019 and December 31, 2018, our long-term debt consisted of the following credit agreements, second lien notes and senior notes:



	Outstanding Principal (in millions)					Interest Rate	Maturity	Security
	March 31, 2019			December 31, 2018
Credit Agreements
2014 Revolving Credit Facility	$	576		$	540	LIBOR plus 3.25%-4.00% ABR plus 2.25%-3.00%	June 30, 2021	Shared First-Priority Lien
2017 Credit Agreement	1,300			1,300		LIBOR plus 4.75% ABR plus 3.75%	December 31, 2022^(a)	Shared First-Priority Lien
2016 Credit Agreement	1,000			1,000		LIBOR plus 10.375% ABR plus 9.375%	December 31, 2021	First-Priority Lien
Second Lien Notes
Second Lien Notes	2,049			2,067		8%	December 15, 2022^(b)	Second-Priority Lien
Senior Notes
5% Senior Notes due 2020	100			100		5%	January 15, 2020	Unsecured
5½% Senior Notes due 2021	100			100		5.5%	September 15, 2021	Unsecured
6% Senior Notes due 2024	144			144		6%	November 15, 2024	Unsecured
Total Debt	5,269			5,251
Less: Current Maturities	(100		)	—
Long-Term Debt	$	5,169		$	5,251


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, 2018.


(a)	The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.


(b)	The Second Lien Notes require principal repayments of approximately $324 million in June 2021, $65 million in December 2021, $67 million in June 2022 and $1,593 million in December 2022.

Deferred Gain and Issuance Costs

As of March 31, 2019, net deferred gain and issuance costs were $203 million, consisting of $293 million of a deferred gain offset by $90 million of deferred issuance costs and original issue discounts. The December 31, 2018 net deferred gain and issuance costs were $216 million, consisting of $313 million of a deferred gain offset by $97 million of deferred issuance costs and original issue discounts.

2014 Revolving Credit Facility

As of March 31, 2019, we had approximately $256 million of available borrowing under our $1 billion revolving credit facility (2014 Revolving Credit Facility), before a $150 million month-end minimum liquidity requirement. Effective May 1, 2019, the borrowing base under this facility was reaffirmed at $2.3 billion. Our 2014 Revolving Credit Facility also includes a sub-limit of $400 million for the issuance of letters of credit. As of March 31, 2019 and December 31, 2018, we had letters of credit outstanding of approximately $168 million and $162 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

Note Repurchases

In the first quarter of 2019, we repurchased $18 million in principal amount of our 8% senior secured second lien notes due December 15, 2022 (Second Lien Notes) for $14 million in cash resulting in a pre-tax gain of $6 million, including the effect of unamortized deferred gain and issuance costs.

Fair Value

We estimate the fair value of fixed-rate debt, which is classified as Level 1, based on prices from known market transactions for our instruments. The estimated fair value of our debt at March 31, 2019 and December 31, 2018, including the fair value of the variable-rate portion, was approximately $4.8 billion and $4.5 billion, respectively, compared to a carrying value of approximately $5.3 billion in both periods.

Other

At March 31, 2019, we were in compliance with all financial and other debt covenants.

All obligations under our 2014 Revolving Credit Facility, 2017 Credit Agreement and 2016 Credit Agreement (collectively, Credit Facilities) as well as our Second Lien Notes and Senior Notes are guaranteed both fully and unconditionally and jointly and severally by all of our material wholly owned subsidiaries.


NOTE 6	JOINT VENTURES

Noncontrolling Interests

The following table presents the changes in noncontrolling interests by JV partners (described in greater detail below), reported in equity and mezzanine equity on the condensed consolidated balance sheets, for the three months ended March 31, 2019 and 2018:



	Equity Attributable to Noncontrolling Interest									Mezzanine Equity - Redeemable Noncontrolling Interests
	Ares JV			BSP JV			Total			Ares JV
	(in millions)
Balance, December 31, 2018	$	15		$	99		$	114		$	756
Net (loss) income attributable to noncontrolling interests	(3		)	(2		)	(5		)	28
Contributions from noncontrolling interest holders, net	—			49			49			—
Distributions accrual	—			(19		)	(19		)	—
Distributions to noncontrolling interest holders	(2		)	—			(2		)	(18		)
Balance, March 31, 2019	$	10		$	127		$	137		$	766

Balance, December 31, 2017	$	—		$	94		$	94		$	—
Net income (loss) attributable to noncontrolling interests	1			(4		)	(3		)	14
Contributions from noncontrolling interest holders, net	33			—			33			714
Distributions to noncontrolling interest holders	(1		)	(14		)	(15		)	(4		)
Balance, March 31, 2018	$	33		$	76		$	109		$	724

Ares Management L.P. (Ares)

Our condensed consolidated statements of operations reflect the full operations of our midstream JV with ECR Corporate Holdings L.P. (ECR), a portfolio company of Ares Management L.P. (Ares), 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)

Our consolidated results reflect the full operations of our development JV with Benefit Street Partners (BSP), with BSP's preferred interest reported in equity on our condensed consolidated balance sheets and BSP’s share of net income (loss) being reported in net income attributable to noncontrolling interests on our condensed consolidated statements of operations. BSP contributed $49 million in the first quarter of 2019, net of transaction costs.

NOTE 7 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

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

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at March 31, 2019 and December 31, 2018 were not material to our 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.

We remain subject to examination by the IRS for calendar years 2016 and 2017. We remain subject to examination by the state of California for the years ended December 31, 2014 through 2017.

NOTE 8 DERIVATIVES

General

We use a variety of derivative instruments 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.

Commodity Price Risk

We did not have any commodity derivatives designated as hedges as of and during the three months ended March 31, 2019 and 2018. As part of our hedging program, we held the following Brent-based crude oil contracts as of March 31, 2019:



	Q2 2019		Q3 2019		Q4 2019		Q1 2020
Sold Calls:
Barrels per day	5,000		—		—		—
Weighted-average price per barrel	$	68.45	$	—	$	—	$	—

Purchased Puts:
Barrels per day	40,000		40,000		35,000		10,000
Weighted-average price per barrel	$	69.75	$	73.13	$	75.71	$	75.00

Sold Puts:
Barrels per day	35,000		40,000		35,000		10,000
Weighted-average price per barrel	$	55.71	$	57.50	$	60.00	$	60.00

The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the BSP JV could affect the timing of the redemption of the JV interest.

Interest-Rate Risk

In May 2018, we entered into 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 4, 2021.

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 contract prices or interest rates and the associated forward curves.

Commodity Contracts

The following table presents the fair values (at gross and net) of our outstanding commodity derivatives as of March 31, 2019 and December 31, 2018 (in millions):



March 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:
Other current assets	$	99		$	(20	)	$	79
Other assets	2			—			2

Liabilities:
Accrued liabilities	(24		)	20			(4		)
Other long-term liabilities	(1		)	—			(1		)
Total derivatives	$	76		$	—		$	76



December 31, 2018
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:
Other current assets	$	252		$	(84	)	$	168
Other assets	23			(9		)	14

Liabilities:
Accrued liabilities	(87		)	84			(3		)
Other long-term liabilities	(10		)	9			(1		)
Total derivatives	$	178		$	—		$	178

Interest-Rate Contracts

As of March 31, 2019 and December 31, 2018, we reported the fair value of our interest rate derivatives of $1 million and $4 million, respectively, in other assets on our condensed consolidated balance sheets. For the three months ended March 31, 2019, we reported a $3 million non-cash derivative loss on these contracts in other non-operating expenses on our condensed consolidated statements of operations.

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 months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019			2018
	(in millions, except per-share amounts)
Net (loss) income	$	(44	)	$	9
Net income attributable to noncontrolling interests	(23		)	(11		)
Net income (loss) attributable to common stock	(67		)	(2		)
Less: net income allocated to participating securities	—			—
Net loss available to common stockholders	$	(67	)	$	(2	)
Weighted-average common shares outstanding - basic	48.7			44.2
Basic EPS	$	(1.38	)	$	(0.05	)

Net (loss) income	$	(44	)	$	9
Net income attributable to noncontrolling interests	(23		)	(11		)
Net loss attributable to common stock	(67		)	(2		)
Less: net income allocated to participating securities	—			—
Net loss available to common stockholders	$	(67	)	$	(2	)
Weighted-average common shares outstanding - basic	48.7			44.2
Dilutive effect of potentially dilutive securities	—			—
Weighted-average common shares outstanding - diluted	48.7			44.2
Diluted EPS	$	(1.38	)	$	(0.05	)
Weighted-average anti-dilutive shares^(a)	2.5			2.5


(a)	Anti-dilutive shares represent potential common shares that are excluded from the computation of diluted EPS.

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:



	Three months ended March 31,
	2019					2018
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	—		$	1	$	—		$	1
Interest cost	1			1		1			1
Expected return on plan assets	(1		)	—		(1		)	—
Recognized actuarial loss	1			—		—			—
Settlement loss	—			—		2			—
Total	$	1		$	2	$	2		$	2

We did not contribute to our defined benefit pension plan in the three months ended March 31, 2019 and contributed $1 million in the three months ended March 31, 2018. We expect to satisfy minimum funding requirements with contributions of $3 million to our defined benefit pension plans during the remainder of 2019. The 2018 settlement loss, which was reclassified from accumulated other comprehensive income, was associated with early retirements.

NOTE 11 REVENUE RECOGNITION

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

The following is a description of our principal activities from which we generate revenue. Revenues are recognized when control of promised goods is transferred to our customers, in an amount that reflects the consideration we expect to receive in exchange for those goods.

Commodity Sales Contracts

We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and control passes to the customer. Our commodity contracts are short term, typically less than a year. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Transportation and processing fees incurred by us prior to control being transferred to customers are recorded as a component of other expenses, net on our condensed consolidated statements of operations.

Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we have a right to invoice once we are able to adequately estimate the consideration (i.e., when market prices are known). Our contracts with customers typically require payment within 30 days following invoicing.

Electricity

The electrical output of the Elk Hills power plant that is not used in our operations is sold to the wholesale power market and to a utility under a power purchase and sales agreement, which includes a capacity payment. Revenue is recognized when obligations under the terms of contracts with our customers are satisfied; generally, this occurs upon delivery of the electricity. We report electricity sales as other revenue on our condensed consolidated statements of operations. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments.

Marketing, Trading and Other

Marketing, trading and other revenue primarily includes our activities associated with storing, transporting and marketing our production as well as third-party volumes.

To transport our natural gas as well as third-party volumes, we have entered into firm pipeline commitments. Depending on market conditions, we may have excess capacity, in which case we may enter into natural gas purchase and sale agreements with third parties. We consider our performance obligations to be satisfied upon transfer of control of the commodity. We have not incurred any significant fees or penalties related to excess capacity on these commitments.

We report our marketing and trading activities on a gross basis with purchases and costs reported in other expenses, net and sales recorded in other revenue on our condensed consolidated statements of operations.

Disaggregation of Revenue

The following table provides disaggregated revenue for the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019			2018
	(in millions)
Oil and gas sales:
Oil	$	480		$	466
NGLs	59			63
Natural gas	62			46
	601			575
Other revenue:
Electricity	34			24
Marketing, trading and other	144			47
Interest income	—			1
	178			72
Net derivative loss from commodity contracts	(89		)	(38		)
Total revenues and other	$	690		$	609

NOTE 12 LEASES

On January 1, 2019, we adopted ASC 842 using the modified retrospective approach that requires us to determine our lease balances as of the date of adoption. Prior periods continue to be reported under accounting standards in effect for those periods. We also elected to carry forward our current accounting treatment for land easements on existing agreements. Mineral leases, including oil and natural gas leases, are not included in the scope of ASC 842.

We have long-term operating leases for commercial office space, drilling rigs, fleet vehicles and certain facilities. In considering whether a contract contains a lease, we first considered whether there was an identifiable asset and then considered how and for what purpose the asset would be used over the contract term.

Our lease liability was determined by measuring the present value of the remaining fixed minimum lease payments as of the date of adoption discounted using our incremental borrowing rate (IBR). In determining our IBR, we considered the average cost of borrowing for publicly traded corporate bond yields, which were adjusted to reflect our credit rating, remaining lease term and frequency of payments.

We elected to combine lease and non-lease components in determining fixed minimum lease payments for our drilling rigs and commercial office space. If applicable, fixed minimum lease payments were reduced by lease incentives for our commercial buildings and increased by mobilization and demobilization fees related to our drilling rigs. Certain of our lease agreements include options to renew, which we exercise at our sole discretion, and we did not include these options in determining our fixed minimum lease payments. Our lease liability does not include options to extend or terminate our leases. Our leases do not include options to purchase the leased property. Lease agreements for our fleet vehicles include residual value guarantees, none of which are recognized in our financial statements until the underlying contingency is resolved.

For all of our asset classes, we elected to keep leases with an initial term of 12 months or less off the balance sheet and have included costs related to these contracts in our short-term lease cost disclosure below. Contracts with terms of one month or less are excluded from our disclosure of short-term lease costs.

For our long-term contracts, variable lease costs were not included in the measurement of our lease balances. Variable lease costs for our drilling rigs included costs to operate, move and repair the rigs. Variable lease costs for certain of our commercial office buildings included utilities and common area maintenance charges. Variable lease costs for our fleet vehicles included other-than-routine maintenance and other various amounts in excess of our fixed minimum rental fee.

Our operating lease costs, including amounts capitalized to property, plant and equipment, for the three months ended March 31, 2019 were as follows:



	Three months ended March 31, 2019
	(in millions)
Operating lease cost	$	12
Short-term lease cost	20
Variable lease cost	5
Total lease cost	$	37

We sublease certain commercial office space to third parties where we are the primary obligor under the head lease. The lease terms on those subleases never extend past the term of the head lease and the sublease contains no extension options or residual value guarantees. Sublease income is recognized based on the contract terms and included as a reduction of operating lease cost under our head lease. For the quarter ended March 31, 2019, sublease income was not material to our condensed consolidated financial statements.

For the quarter ended March 31, 2019, we paid $9 million and $3 million for our operating lease liabilities, which were reported in net cash used in investing activities and net cash provided by operating activities in our condensed consolidated statement of cash flows, respectively.

Our right-of-use assets for operating leases, net of accumulated amortization, were approximately $54 million at March 31, 2019, which is reported in other assets on our consolidated balance sheet. Supplemental balance sheet information related to our operating leases was as follows:



	March 31,
	2019
	(in millions)
Operating lease right-of-use assets, net	$	54

Current liabilities	$	27
Long-term liabilities	27
Total operating lease liabilities	$	54

Weighted-average remaining lease term (in years)	2.9
Weighted-average discount rate	11.5		%

As part of our company-wide consolidation of office space, we will be vacating certain office space in 2019, some of which we may sublease. Should we enter into a sublease agreement, we will evaluate the carrying value of our right-of-use asset, along with the carrying value of related tenant improvements, for impairment based on future identifiable cash flows. For the period ended March 31, 2019, we recognized an impairment of $3 million. We do not expect to terminate leases for vacated office space before the expiration of the lease term. Where we have decided to not sublease vacated commercial office space, we will shorten the useful life of the right-of-use assets and related tenant improvements to recover our remaining costs over our expected period of use. Once the leased office space is abandoned, lease costs will be classified as other non-operating expenses, net on our condensed consolidated statements of operations.

Maturities of our operating lease liabilities at March 31, 2019 are as follows:



	March 31,
	2019
	(in millions)
2019	$	27
2020	18
2021	7
2022	4
2023	2
Thereafter	6
Less: Interest	(10		)
Present value of lease liabilities	$	54

We have entered into contracts for commercial office space and facilities that are under construction as of March 31, 2019. These leases are not included in our lease population at March 31, 2019 as the lease terms have not commenced because we do not control the assets during construction. We will apply the new lease standard when the asset is placed in service by us, which is expected to be in January and June 2020. Payments for these contracts were included in the table of our future minimum lease payments as of December 31, 2018, which is shown below.

At December 31, 2018, future minimum lease payments for noncancelable operating leases under ASC 840 (excluding oil and natural gas and other mineral leases, utilities, taxes, insurance and common area maintenance expenses) were:



	December 31,
	2018
	(in millions)
2019	$	12
2020	8
2021	7
2022	7
2023	6
Thereafter	28
Total	$	68

Rental expense for operating leases under ASC 840 was $2.8 million for the three months ended March 31, 2018. Rental income from subleases for the three months ended March 31, 2018 was not significant.

NOTE 13 INCOME TAXES

For the three months ended March 31, 2019 and 2018, 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 are able to actually achieve.

NOTE 14 ASSET DIVESTITURE

On May 1, 2019, we sold 50% of our working interest and transferred operatorship in certain zones of our Lost Hills field, located in the San Joaquin basin, for total consideration in excess of $200 million, consisting of approximately $168 million in cash and a carried 200-well development program to be drilled through 2023 with an estimated minimum value of $35 million. The proceeds were used to pay down our 2014 Revolving Credit Facility.


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

General

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

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. These and other factors make it impossible to predict realized prices reliably.

Global oil prices gradually increased in the first quarter of 2019 from the decline that began late in the fourth quarter of 2018. However, the average Brent crude oil price in the first quarter of 2019 did not return to its previous 2018 highs and was lower compared to the same period of 2018. Prices for natural gas liquids (NGLs) decreased between comparative periods. On average, domestic natural gas prices were higher in the first quarter of 2019 than the comparable period of 2018 largely due to higher winter demand in 2019.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019		2018
Brent oil ($/Bbl)	$	63.90	$	67.18
WTI oil ($/Bbl)	$	54.90	$	62.87
NYMEX gas ($/MMBtu)	$	3.24	$	2.87


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

We currently sell all of our crude oil into the California refining market, which offers relatively favorable pricing compared to other U.S. regions for similar grades. California is heavily reliant on imported sources of energy, with approximately 73% of the oil consumed in 2018 imported from outside the state. A vast majority 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 prices. We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades.

Price realizations for NGLs improved as a percentage of Brent due to higher valued local sales in California. 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.

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 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 is made up of 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, generally, have a net negative effect on our results.

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. Additionally, we use part of the electricity from the Elk Hills power plant to reduce operating costs at our Elk Hills and certain nearby fields and to increase reliability. The remaining electricity is sold to the wholesale power market and a utility under a power purchase and sales agreement expiring in December 2020, which includes a capacity payment. The price obtained for excess power impacts our earnings but generally by an insignificant amount.

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 in case of price deterioration. We built our 2019 and 2020 commodity hedge positions to protect our downside risk without significantly limiting our upside potential. We can give no assurances that our hedges will be adequate to accomplish our objectives. 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 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.

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 approximately 2.2 million net mineral acres, approximately 60% of which is held in fee and over 15% is held by production. Our oil and gas leases have primary terms ranging from one to ten years. Once production commences, the leases are extended through the end of their producing life. We also own or control a network of integrated infrastructure that complements our operations including gas 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.

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 recover our share of capital and production costs, and 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 15% of our production for the quarter ended March 31, 2019.

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.

With our significant land holdings in California, we have undertaken new initiatives to unlock additional value from our real estate. Our real estate development initiatives include exploring renewable energy opportunities on our land such as solar energy projects, agricultural activities (such as the production of fruits and nuts) and other commercial real estate uses. We are also exploring carbon dioxide capture and storage projects and reclaimed water opportunities.

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 during the year.

Joint Ventures

We have a number of joint ventures (JVs) that allow us to accelerate the development of our assets while providing us with operational and financial flexibility as well as near-term production benefits.

In our JV with Benefit Street Partners (BSP), BSP has a total commitment of $250 million, of which an aggregate of $200 million has been funded with $50 million funded in the first quarter of 2019.

In our JV with Macquarie Infrastructure and Real Assets Inc. (MIRA), MIRA has a total commitment of $140 million, of which an aggregate of $122 million has been funded with $7 million funded in the first quarter of 2019. We expect the remaining balance of MIRA's commitment to be invested in 2019.

Asset Divestiture

Fixed and Variable Costs

Our production costs include variable costs that fluctuate with production levels, and 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. Overall, we believe approximately one-third of our operating costs are fixed over the life cycle of our fields. 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 production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019	2018
Oil (MBbl/d)
San Joaquin Basin	55	49
Los Angeles Basin	25	24
Ventura Basin	4	4
Total	84	77
NGLs (MBbl/d)
San Joaquin Basin	14	15
Ventura Basin	1	1
Total	15	16
Natural gas (MMcf/d)
San Joaquin Basin	165	143
Los Angeles Basin	2	1
Ventura Basin	7	7
Sacramento Basin	28	31
Total	202	182

Total Production (MBoe/d)	133	123


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.

The following table sets forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX for our products for the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019				2018
	Price			Realization	Price			Realization
Oil ($ per Bbl)
Brent	$	63.90			$	67.18

Realized price, without hedge	$	63.30		99%	$	67.26		100%
Settled hedges	1.98				(4.49		)
Realized price, with hedge	$	65.28		102%	$	62.77		93%

WTI	$	54.90			$	62.87
Realized price, without hedge	$	63.30		115%	$	67.26		107%
Realized price, with hedge	$	65.28		119%	$	62.77		100%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	42.52		67%	$	43.13		64%
Realized price (% of WTI)	$	42.52		77%	$	43.13		69%

Natural gas
NYMEX ($/MMBTU)	$	3.24			$	2.87

Realized price, w/out hedge ($/Mcf)	$	3.43		106%	$	2.81		98%
Settled hedges	(0.05		)		—
Realized price, with hedge ($/Mcf)	$	3.38		104%	$	2.81		98%

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2018 to March 31, 2019 are discussed below:



	March 31, 2019			December 31, 2018
	(in millions)
Cash	$	43		$	17
Trade receivables	$	296		$	299
Inventories	$	71		$	69
Other current assets, net	$	167		$	255
Property, plant and equipment, net	$	6,548		$	6,455
Other assets	$	105		$	63
Current maturities of long-term debt	$	100		$	—
Accounts payable	$	304		$	390
Accrued liabilities	$	285		$	217
Long-term debt	$	5,169		$	5,251
Deferred gain and issuance costs, net	$	203		$	216
Other long-term liabilities	$	692		$	575
Mezzanine equity	$	766		$	756
Equity attributable to common stock	$	(426	)	$	(361	)
Equity attributable to noncontrolling interests	$	137		$	114

Cash at March 31, 2019 and December 31, 2018 included approximately $26 million and $2 million, respectively, which is restricted for capital investments and distributions to BSP. See Liquidity and Capital Resources for our cash flow analysis.

The decrease in other current assets, net was primarily due to changes in the current portion of our derivative assets.

The increase in property, plant and equipment, net primarily reflected capital investments for the period and changes to our asset retirement obligations (ARO) resulting from idle well regulations enacted in the first quarter of 2019, partially offset by depreciation, depletion and amortization.

Other assets increased primarily due to recording a right-of-use asset for operating leases as a result of adopting new accounting rules on January 1, 2019 which impacts the current period but not the prior period. This increase was partially offset by fair value changes in our long-term derivative assets.

Current maturities of long-term debt reflected $100 million for our 5% senior notes due in 2020.

The reduction in accounts payable for the quarter ended March 31, 2019 reflected the decrease in activity between periods.

Accrued liabilities reflected higher accrued interest and property tax balances due to the timing of payments, accrued distribution to our JV partner BSP and the current portion of our operating lease liability resulting from the adoption of new lease accounting rules. These increases were partially offset by lower accrued employee-related costs, which primarily reflected employee bonus payments in the first quarter of 2019.

Other long-term liabilities reflected the increases in ARO due to the new idle well regulations and long-term operating lease liabilities due to the adoption of new lease accounting rules. The annual incremental cash expenditures for ARO resulting from the new idle well regulations are not expected to be material.

Equity attributable to common stock decreased primarily as a result of the net loss for the period.

The increase in equity attributable to noncontrolling interests reflected contributions made by the BSP JV, partially offset by distributions payable to and net loss allocated to the Ares and BSP JVs during the period. See Item 1 – Financial Statements – Note 6 Joint Ventures for more information.

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:



	Three months ended March 31,
	2019		2018
Production costs	$	19.46	$	19.08
Production costs, excluding effects of PSC-type contracts^(a)	$	18.01	$	17.47
Field general and administrative expenses^(b)	$	1.25	$	0.72
Field depreciation, depletion and amortization^(b)	$	9.27	$	9.90
Field taxes other than on income^(b)	$	2.67	$	2.70


(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 consolidated operations for the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
	2019			2018
	(in millions)
Oil and gas sales	$	601		$	575
Net derivative loss	(89		)	(38		)
Other revenue	178			72
Production costs	(233		)	(212		)
General and administrative expenses	(83		)	(63		)
Depreciation, depletion and amortization	(118		)	(119		)
Taxes other than on income	(41		)	(38		)
Exploration expense	(10		)	(8		)
Other expenses, net	(148		)	(61		)
Interest and debt expense, net	(100		)	(92		)
Net gain on early extinguishment of debt	6			—
Other non-operating expenses	(7		)	(7		)
(Loss) income before income taxes	(44		)	9
Income tax	—			—
Net (loss) income	(44		)	9
Net income attributable to noncontrolling interests	(23		)	(11		)
Net loss attributable to common stock	$	(67	)	$	(2	)

Adjusted net income	$	31		$	8
Adjusted EBITDAX	$	301		$	250
Effective tax rate	—		%	—		%

Three months ended March 31, 2019 vs. 2018

Oil and gas sales increased 5%, or $26 million, for the three months ended March 31, 2019 compared to the same period of 2018 due to increases of approximately $41 million and $6 million from higher oil and natural gas production, respectively, and a $10 million increase in realized natural gas prices. These increases were partially offset by $28 million primarily from lower realized oil prices and $3 million from decreased NGL production.

Our total daily production volumes averaged 133 MBoe in the three months ended March 31, 2019, compared with 123 MBoe in the comparable period of 2018, representing a year-over-year increase of 8%. Our first quarter 2019 volumes included volumes from the acquisition of the remaining working, surface and mineral interests in the Elk Hills unit from Chevron U.S.A., Inc. (the Elk Hills transaction), which closed in the second quarter of 2018.

Net derivative loss was $89 million for the three months ended March 31, 2019, compared to $38 million in the same period of 2018, representing an overall change of $51 million. In the first quarter of 2019, we had a non-cash derivative loss of $103 million which was partially offset by proceeds from settlements of $14 million. In the first quarter of 2018, we recognized a non-cash derivative loss of $7 million related to the fair value of our derivative contracts and settlement payments of $31 million. See the table in the Derivative Gains and Losses section below.

The increase in other revenue of $106 million to $178 million for the three months ended March 31, 2019, compared to $72 million in the same period of 2018, was largely the result of higher trading activity.

Production costs for the three months ended March 31, 2019 increased $21 million to $233 million, compared to $212 million for the same period of 2018, resulting in a 10% increase. The increase is attributable to the Elk Hills transaction, cash-settled stock-based compensation, energy costs and other items.

Our G&A expenses increased $20 million to $83 million for the three months ended March 31, 2019 compared to the same period of 2018. Our cash-settled stock-based compensation expense increased approximately $7 million primarily due to the increase in our stock price in the first quarter of 2019 as noted in the stock-based compensation table below. Additionally, our G&A expenses increased following the Elk Hills transaction by approximately $3 million since certain costs are no longer collected from our former working interest partner.

The increase in other expenses of $87 million to $148 million for the three months ended March 31, 2019, compared to $61 million for the same period of 2018, was largely the result of higher trading activity.

Net income attributable to noncontrolling interests increased by $12 million for the three months ended March 31, 2019, compared to the same period of 2018, largely the result of entering into the Ares JV in February 2018.

Stock-Based Compensation

Our consolidated results of operations for the three months ended March 31, 2019 and 2018 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 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 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 partially or fully cash-settled awards based on our stock price as of 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 as of the end of each reporting period. Cash-settled awards, including executive awards partially settled in cash, account for approximately 50% of our total outstanding awards. Our stock price increased $8.67 or 51% from $17.04 as of December 31, 2018 to $25.71 as of March 31, 2019. The increase in our stock price resulted in higher cash-settled stock-based compensation expense. Equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation is included in both G&A expenses and production costs as shown in the table below:



	Three months ended March 31,
	2019		2018
	(in millions, except per Boe amounts)
General and administrative expenses
Cash-settled awards	$	10	$	3
Equity-settled awards	3		3
Total stock-based compensation in G&A	$	13	$	6
Total stock-based compensation in G&A per Boe	$	1.09	$	0.54

Production costs
Cash-settled awards	$	3	$	1
Equity-settled awards	1		1
Total stock-based compensation in production costs	$	4	$	2
Total stock-based compensation in production costs per Boe	$	0.33	$	0.18

Total company stock-based compensation	$	17	$	8
Total company stock-based compensation per Boe	$	1.42	$	0.72

Derivative Gains and Losses

The following table presents the components of our net derivative loss from commodity contracts and our non-cash derivative loss from interest-rate contracts. Our non-cash derivative loss from interest-rate contracts is reported in other non-operating expenses.



	Three months ended March 31,
	2019			2018
	(in millions)
Commodity Contracts:
Non-cash derivative loss, excluding noncontrolling interest	$	(97	)	$	(7	)
Non-cash derivative loss - noncontrolling interest	(6		)	—
Net proceeds (payments) on settled commodity derivatives	14			(31		)
Net derivative loss from commodity contracts	$	(89	)	$	(38	)

Interest-Rate Contracts:
Non-cash derivative loss	$	(3	)	$	—

Non-GAAP Financial Measures

Our results of operations 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 U.S. generally accepted accounting principles (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 income and presents the GAAP financial measure of net loss attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net income per diluted share:



	Three months ended March 31,
	2019			2018
	(in millions, except share data)
Net (loss) income	$	(44	)	$	9
Net income attributable to noncontrolling interests	(23		)	(11		)
Net loss attributable to common stock	(67		)	(2		)
Unusual, infrequent and other items:
Non-cash derivative loss from commodities, excluding noncontrolling interest	97			7
Non-cash derivative loss from interest-rate contracts	3			—
Early retirement costs	—			2
Net gain on early extinguishment of debt	(6		)	—
Other, net	4			1
Total unusual, infrequent and other items	98			10
Adjusted net income	$	31		$	8

Net loss attributable to common stock per diluted share	$	(1.38	)	$	(0.05	)
Adjusted net income per diluted share	$	0.63		$	0.18

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 March 31,
	2019			2018
	(in millions)
Net (loss) income	$	(44	)	$	9
Interest and debt expense, net	100			92
Depreciation, depletion and amortization	118			119
Exploration expense	10			8
Unusual, infrequent and other items	98			10
Other non-cash items	19			12
Adjusted EBITDAX	$	301		$	250

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:



	Three months ended March 31,
	2019		2018
	(in millions)
Net cash provided by operating activities	$	158	$	200
Cash interest	72		61
Exploration expenditures	4		6
Working capital changes	67		(18		)
Other, net	—		1
Adjusted EBITDAX	$	301	$	250

Liquidity and Capital Resources

Cash Flow Analysis



	Three months ended March 31,
	2019			2018
	(in millions)
Net cash provided by operating activities	$	158		$	200
Net cash used in investing activities:
Capital investments, including accruals	$	(178	)	$	(134	)
Acquisitions, divestitures and other	$	(4	)	$	(4	)
Net cash provided by financing activities	$	50		$	412

Our net cash provided by operating activities is sensitive to many variables, including changes in commodity prices. Commodity price sensitivity also leads to changes in other variables in our business including adjustments to our capital program. Our operating cash flow decreased 21%, or $42 million, to $158 million for the three months ended March 31, 2019 from $200 million in the same period of 2018. Changes to working capital in the first quarter of 2019 reduced our operating cash flow by $24 million compared to an increase of $68 million in the first quarter of 2018. Before the effect of working capital changes, operating cash flow was higher in the first quarter of 2019, primarily resulting from higher volumes partially offset by lower realized oil prices.

Our net cash used in investing activities of $182 million for the three months ended March 31, 2019 primarily reflected $178 million of capital investments (including $47 million in capital-related accrual changes), of which $27 million was funded by BSP. For the three months ended March 31, 2018, our net cash used in investing activities of $138 million primarily included approximately $134 million of capital investments (including $5 million in capital-related accruals).

Our net cash provided by financing activities of $50 million for the three months ended March 31, 2019 primarily comprised $49 million in net contributions from BSP and net proceeds from our 2014 Revolving Credit Facility of $36 million, partially offset by $20 million of distributions to our Ares JV partner and $14 million of debt repurchases on our Second Lien Notes. For the three months ended March 31, 2018, our net cash provided by financing activities of $412 million primarily comprised $747 million in net contributions from our Ares JV partner and $50 million from the issuance of common stock, partially offset by $363 million of net payments on our 2014 Revolving Credit Facility, $18 million of distributions paid to our JV partners and $2 million of debt repurchases on our Second Lien Notes.

Liquidity

Our primary sources of liquidity and capital resources are cash flow from operations and available borrowing capacity under our 2014 Revolving Credit Facility. We also rely on other sources such as JVs to supplement our capital program, fund acquisitions and for other corporate purposes. We expect that the combination of these sources of funds will be adequate for our 2019 capital program, debt service and operating needs.

As of March 31, 2019, our long-term debt consisted of the following credit agreements, second lien notes and senior notes:



	Outstanding Principal (in millions)			Interest Rate	Maturity	Security
Credit Agreements
2014 Revolving Credit Facility	$	576		LIBOR plus 3.25%-4.00% ABR plus 2.25%-3.00%	June 30, 2021	Shared First-Priority Lien
2017 Credit Agreement	1,300			LIBOR plus 4.75% ABR plus 3.75%	December 31, 2022^(a)	Shared First-Priority Lien
2016 Credit Agreement	1,000			LIBOR plus 10.375% ABR plus 9.375%	December 31, 2021	First-Priority Lien
Second Lien Notes
Second Lien Notes	2,049			8%	December 15, 2022^(b)	Second-Priority Lien
Senior Notes
5% Senior Notes due 2020	100			5%	January 15, 2020	Unsecured
5½% Senior Notes due 2021	100			5.5%	September 15, 2021	Unsecured
6% Senior Notes due 2024	144			6%	November 15, 2024	Unsecured
Total	5,269
Less: Current Maturities	(100		)
Long-Term Debt	$	5,169


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, 2018.


(a)	The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.


(b)	The Second Lien Notes require principal repayments of approximately $324 million in June 2021, $65 million in December 2021, $67 million in June 2022 and $1,593 million in December 2022.

2014 Revolving Credit Facility

As of March 31, 2019, we had approximately $256 million of available borrowing capacity, before a $150 million month-end minimum liquidity requirement. Effective May 1, 2019, the borrowing base under this facility was reaffirmed at $2.3 billion. Our $1 billion senior revolving loan facility (2014 Revolving Credit Facility) also includes a sub-limit of $400 million for the issuance of letters of credit. As of March 31, 2019 and December 31, 2018, we had letters of credit outstanding of approximately $168 million and $162 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

Note Repurchases

Other

At March 31, 2019, we were in compliance with all financial and other debt covenants.

A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on March 31, 2019 would result in a $4 million change in annual interest expense before the impact of hedges.

Derivatives

Significant changes in oil and natural gas prices 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 have utilized various derivative instruments to hedge price risk.

Commodity Contracts

Our strategy for protecting our cash flow, operating margin and capital program, while maintaining adequate liquidity, includes our hedging program. We currently have the following Brent-based crude oil contracts, as of May 2, 2019:



	Q2 2019		Q3 2019		Q4 2019		Q1 2020		Q2 2020
Sold Calls:
Barrels per day	5,000		—		—		—		—
Weighted-average price per barrel	$	68.45	$	—	$	—	$	—	$	—

Purchased Puts:
Barrels per day	40,000		40,000		35,000		20,000		10,000
Weighted-average price per barrel	$	69.75	$	73.13	$	75.71	$	72.50	$	70.00

Sold Puts:
Barrels per day	35,000		40,000		35,000		20,000		10,000
Weighted-average price per barrel	$	55.71	$	57.50	$	60.00	$	57.50	$	55.00

Swaps:
Barrels per day	—		—		—		5,000^(a)		5,000^(b)
Weighted-average price per barrel	$	—	$	—	$	—	$	70.29	$	70.05


(a)	A counterparty has the option to increase swap volumes by up to 5,000 barrels per day at a weighted-average Brent price of $70.29 for the first quarter of 2020.


(b)	A counterparty has the option to increase swap volumes by up to 5,000 barrels per day at a weighted-average Brent price of $70.05 for the second quarter of 2020.

Interest-Rate Contracts

In May 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.

2019 Capital Program

We entered 2019 with an internally funded capital program of $300 to $385 million, which may be adjusted during the course of the year depending on commodity prices. We obtained an additional $50 million from our BSP JV partner in the first quarter of 2019 and continue discussions to obtain additional investments from new and existing JV partners that could support a 2019 capital program, including JV funding, of approximately $500 million.

We are focusing our 2019 capital on oil projects. Our capital program will be largely directed to short payout projects, such as primary drilling and capital workovers, and low-risk projects including waterflood and steamflood investments that maintain base production. We will continue to focus on our core fields: Elk Hills and surrounding areas, Wilmington, Kern Front and the delineation and appraisal of other long-term prospects.

We plan to use 60% of our capital program on drilling and development of conventional and unconventional resources. The depth of our conventional wells is expected to range from 2,000 to 15,000 feet. Our conventional program includes approximately 140 wells primarily in Wilmington, Huntington Beach, Kern Front and Mount Poso, which will largely consist of waterfloods and steamfloods along with some primary drilling. We also intend to drill approximately 10 unconventional wells mainly in the Buena Vista area. With continued focus on cost savings and efficiencies, many of our deep conventional and unconventional wells have become more competitive.

We also plan to use approximately 15% of our 2019 capital program for capital workovers on existing well bores. Capital workovers are some of the highest Value Creation Index projects in our portfolio and generally include well deepenings, recompletions, changes of lift methods and other activities designed to add incremental productive intervals and reserves.

Further, approximately 15% of our 2019 capital program is intended for facilities development for our newer projects, including pipeline and gathering line interconnections, gas compression and water management systems, and for mechanical integrity, safety and environmental projects. About 10% is intended to be used for exploration and other corporate uses.

Streamlining our business and reducing costs, together with higher realized prices, have enabled us to invest in our assets and grow our production. We will continue to build our inventory of available projects, which will position us to accelerate value by utilizing third-party capital and take advantage of potential future commodity price increases.

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 March 31, 2019 and December 31, 2018 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.

We remain subject to examination by the IRS for calendar years 2016 and 2017. We remain subject to examination by the state of California for the years ended December 31, 2014 through 2017.

Significant Accounting and Disclosure Changes

See Note 2 Accounting and Disclosure Changes in the Notes to the Condensed Consolidated Financial Statements included in Part I 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


•	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

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:


•	commodity price changes


•	debt limitations on our financial flexibility


•	insufficient cash flow to fund planned investments, debt repurchases, distributions to JV partners or changes to our capital plan


•	inability to enter 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 and

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


•	insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors


•	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, transportation or storage constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events


•	factors discussed in Item 1A – Risk Factors of our Form 10-K for the year ended December 31, 2018.

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 3.	Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, 2019, 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 2018 Form 10-K, except as discussed below.

Commodity Price Risk

As a result of our hedge positions for 2019 production, we protected our downside price risk on approximately 40,000 barrels of oil per day at approximately $70 Brent per barrel for the second quarter of 2019. For the third and fourth quarters of 2019, we protected our downside price risk on approximately 40,000 and 35,000 barrels of oil per day at approximately $73 Brent and $76 Brent per barrel, respectively. The underlying instruments in our 2019 hedge program are puts and put spreads that provide full upside to oil price movements. For the first and second quarters of 2020, we protected our downside risk on approximately 25,000 and 15,000 barrels per day at approximately $72 Brent and $70 Brent per barrel, respectively. Our 2019 and 2020 put spreads provide downside price protection until Brent prices range between $55 and $60 per barrel, at which point we receive Brent plus approximately $15 per barrel.

See additional hedging information in Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.


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 March 31, 2019.

During the first quarter of 2019, we implemented new internal controls to support the adoption of the new accounting standard for leases, ASC 842. 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) that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION


Item 1.	Legal Proceedings

For information regarding legal proceedings, see Note 7 Lawsuits, Claims and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q and Part I, Item 3, Legal Proceedings in the Form 10-K for the year ended December 31, 2018.


Item 1.A.	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, 2018.


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*	Form of 2019 Nonstatutory Stock Option Award Terms and Conditions.

10.2*	Form of 2019 Restricted Stock Unit Award Terms and Conditions.

10.3*	Form of 2019 Performance Stock Unit Award Terms and Conditions.

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*	XBRL Instance Document.

101.SCH*	XBRL Taxonomy Extension Schema Document.

101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.

* - Filed herewith

SIGNATURES

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



	CALIFORNIA RESOURCES CORPORATION



DATE:	May 2, 2019	/s/ Roy M. Pineci
		Roy M. Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)