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, ~~2018~~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.)

~~9200 Oakdale Avenue,~~27200 Tourney Road, Suite ~~900~~315 ~~Los Angeles,~~Santa Clarita, California (Address of principal executive offices)		~~91311~~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 ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ 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 ~~definition~~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	oþ	Accelerated Filer	þo	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 þNo

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, ~~2018~~2019	~~45,337,486~~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	2218
	General	2218
	Business Environment and Industry Outlook	2218
	Seasonality	2320
	Joint Ventures	2320
	~~Private Placement~~Asset Divestiture	25
	~~Acquisitions and Divestitures~~	2520
	Operations	2619
	Fixed and Variable Costs	2619
	Production and Prices	2721
	Balance Sheet Analysis	2822
	~~Statement~~Statements of Operations Analysis	2923
	Liquidity and Capital Resources	3328
	~~2018~~2019 Capital Program	3631
	Lawsuits, Claims, ~~Contingencies~~Commitments and ~~Commitments~~Contingencies	3731
	Significant Accounting and Disclosure Changes	3731
	~~Safe Harbor Statement Regarding Outlook and~~ Forward-Looking ~~Information~~Statements	3832
Item 3	Quantitative and Qualitative Disclosures About Market Risk	3933
Item 4	Controls and Procedures	3933

Part II
Item 1	Legal Proceedings	4034
Item 1A	Risk Factors	4034
Item 5	Other Disclosures	4034
Item 6	Exhibits	4135

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of March 31, ~~2018~~2019 and December 31, ~~2017~~2018

(in millions, except share data)


	March 31,			December 31,			March 31,			December 31,
	2018			2017			2019			2018
CURRENT ASSETS
Cash and cash equivalents	$	494		$	20
Cash							$	43		$	17
Trade receivables	244			277			296			299
Inventories	56			56			71			69
Other current assets, net	155			130			167			255
Total current assets	949			483			577			640
PROPERTY, PLANT AND EQUIPMENT	21,397			21,260			22,734			22,523
Accumulated depreciation, depletion and amortization	(15,683		)	(15,564		)	(16,186		)	(16,068		)
Total property, plant and equipment, net	5,714			5,696			6,548			6,455
OTHER ASSETS	36			28			105			63
TOTAL ASSETS	$	6,699		$	6,207		$	7,230		$	7,158


CURRENT LIABILITIES
Current maturities of long-term debt							100			—
Accounts payable	292			257			304			390
Accrued liabilities	514			475			285			217
Total current liabilities	806			732			689			607
LONG-TERM DEBT	4,941			5,306			5,169			5,251
DEFERRED GAIN AND ISSUANCE COSTS, NET	275			287			203			216
OTHER LONG-TERM LIABILITIES	607			602			692			575
MEZZANINE EQUITY
Redeemable noncontrolling interest	724			—
Redeemable noncontrolling interests							766			756
EQUITY
Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at March 31, 2018 and December 31, 2017	—			—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (March 31, 2018 - 45,337,486 and December 31, 2017 - 42,901,946)	—			—
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	4,930			4,879			4,989			4,987
Accumulated deficit	(5,672		)	(5,670		)	(5,409		)	(5,342		)
Accumulated other comprehensive loss	(21		)	(23		)	(6		)	(6		)
Total equity attributable to common stock	(763		)	(814		)	(426		)	(361		)
Noncontrolling interests	109			94
Equity attributable to noncontrolling interests							137			114
Total equity	(654		)	(720		)	(289		)	(247		)
TOTAL LIABILITIES AND EQUITY	$	6,699		$	6,207		$	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, ~~2018~~2019 and ~~2017~~2018

(in millions, except share data)


	Three months ended March 31,						Three months ended March 31,
	2018			2017			2019			2018
REVENUES AND OTHER
Oil and gas sales	$	575		$	487		$	601		$	575
Net derivative (losses) gains	(38		)	73
Net derivative loss from commodity contracts							(89		)	(38		)
Other revenue	72			30			178			72
Total revenues and other	609			590			690			609

COSTS AND OTHER
Production costs	212			211			233			212
General and administrative expenses	63			63			83			63
Depreciation, depletion and amortization	119			140			118			119
Taxes other than on income	38			33			41			38
Exploration expense	8			6			10			8
Other expenses, net	61			22			148			61
Total costs and other	501			475			633			501
OPERATING INCOME	108			115			57			108

NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(92		)	(84		)	(100		)	(92		)
Net gains on early extinguishment of debt	—			4
Gains on asset divestitures	—			21
Net gain on early extinguishment of debt							6			—
Other non-operating expenses	(7		)	(4		)	(7		)	(7		)
INCOME BEFORE INCOME TAXES	9			52
Income tax benefit	—			—
NET INCOME	9			52
(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	(11		)	1			(23		)	(11		)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(2	)	$	53
NET LOSS ATTRIBUTABLE TO COMMON STOCK							$	(67	)	$	(2	)

Net (loss) income attributable to common stock per share
Net loss attributable to common stock per share
Basic	$	(0.05	)	$	1.23		$	(1.38	)	$	(0.05	)
Diluted	$	(0.05	)	$	1.22		$	(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, ~~2018~~2019 and ~~2017~~2018

(in millions)

Three months ended
March 31,
2018 2017
Net income $ 9
$ 52
Other comprehensive income items:
Reclassification to income of realized losses on pension and postretirement^(a)
2
3
Total other comprehensive income, net of tax 2
3
Comprehensive (income) loss attributable to noncontrolling interests (11 ) 1
Comprehensive income attributable to common stock $ —
$ 56



	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, ~~2018~~2019 and ~~2017.~~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, ~~2018~~2019 and ~~2017~~2018

(in millions)


	Three months ended March 31,						Three months ended March 31,
	2018			2017			2019			2018
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	9		$	52
Adjustments to reconcile net income to net cash provided by operating activities:
Net (loss) income							$	(44	)	$	9
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	119			140			118			119
Net derivative (gains) losses	38			(73		)
Net payments on settled derivatives	(31		)	(1		)
Net gains on early extinguishment of debt	—			(4		)
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	(19		)	(18		)	(18		)	(19		)
Gains on asset divestitures	—			(21		)
Dry hole expenses							3			2
Other non-cash charges to income, net	14			15			26			14
Dry hole expenses	2			1
Changes in operating assets and liabilities, net	68			42			(24		)	68
Net cash provided by operating activities	200			133			158			200

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(139		)	(50		)	(131		)	(139		)
Changes in capital investment accruals	5			17			(47		)	5
Asset divestitures	—			33
Acquisitions and other	(4		)	—
Acquisitions							(2		)	(3		)
Other							(2		)	(1		)
Net cash used in investing activities	(138		)	—			(182		)	(138		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from 2014 Revolving Credit Facility	81			221			615			81
Repayments of 2014 Revolving Credit Facility	(444		)	(299		)	(579		)	(444		)
Payments on 2014 Term Loan	—			(41		)
Debt repurchases	(2		)	(24		)	(14		)	(2		)
Debt transaction costs	—			(2		)
Contribution from noncontrolling interest holders, net	747			49
Contributions from noncontrolling interest holders, net							49			747
Distributions paid to noncontrolling interest holders	(18		)	—			(20		)	(18		)
Issuance of common stock	50			1			—			50
Shares canceled for taxes	(2		)	—			(1		)	(2		)
Net cash provided (used) by financing activities	412			(95		)
Increase in cash and cash equivalents	474			38
Cash and cash equivalents—beginning of period	20			12
Cash and cash equivalents—end of period	$	494		$	50
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, ~~2018~~2019 and ~~2017~~2018

(in millions)

Common Stock Additional Paid-in Capital Accumulated Deficit
Accumulated Other
Comprehensive
(Loss) Income
Equity Attributable to Common Stock Noncontrolling Interest Total Equity
Balance, December 31, 2016 $ —
$ 4,861
$ (5,404 ) $ (14 ) $ (557 ) $ —
$ (557 )
Net income (loss) —
—
53
—
53
(1 ) 52
Contribution from noncontrolling interest holders, net —
—
—
—
—
49
49
Other comprehensive income —
—
—
3
3
—
3
Share-based compensation, net —
6
—
—
6
—
6
Balance, March 31, 2017 $ —
$ 4,867
$ (5,351 ) $ (11 ) $ (495 ) $ 48
$ (447 )


	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Accumulated Other Comprehensive (Loss) Income			Equity Attributable to Common Stock			Noncontrolling Interest			Total Equity			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	)	$	4,879	$	(5,670	)	$	(23	)	$	(814	)	$	94		$	(720	)
Net (loss) income^(a)	—		—		(2		)	—			(2		)	(3		)	(5		)
Net loss																				—		(2		)	—			(2		)	(3		)	(5		)
Contribution from noncontrolling interest holders, net	—		—		—			—			—			33			33			—		—			—			—			33			33
Distributions paid to noncontrolling interest holders	—		—		—			—			—			(15		)	(15		)
Distributions to noncontrolling interest holders																				—		—			—			—			(15		)	(15		)
Issuance of common stock	—		50		—			—			50			—			50			50		—			—			50			—			50
Other comprehensive income	—		—		—			2			2			—			2			—		—			2			2			—			2
Share-based compensation, net	—		1		—			—			1			—			1			1		—			—			1			—			1
Balance, March 31, 2018	$	—	$	4,930	$	(5,672	)	$	(21	)	$	(763	)	$	109		$	(654	)	$	4,930	$	(5,672	)	$	(21	)	$	(763	)	$	109		$	(654	)


~~(a)~~Note:	~~Excludes $14 million of consolidated net income attributable~~ The above table excludes amounts related to redeemable noncontrolling ~~interest~~interests recorded in mezzanine equity. See Note 6Joint 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, ~~2018~~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 remained a wholly owned subsidiary of Occidental until November 30, 2014. On November 30, 2014, Occidental distributed shares of our common stock on a pro-rata basis to Occidental stockholders (the Spin-off). Wewe became an independent, publicly traded company on December 1, 2014. ~~Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which were distributed to Occidental stockholders on March 24, 2016.~~

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘~~company,~~Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation ~~and its subsidiaries, and all references to ‘‘Occidental’’ refer to Occidental Petroleum Corporation, our former parent,~~ 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, ~~2018~~2019 and December 31, ~~2017~~2018 and the statements of operations, comprehensive income, cash flows and equity for the three months ended March 31, 2019 and 2018, ~~and 2017.~~as applicable. We have eliminated all ~~of our~~ significant intercompany transactions and accounts. We account for our share of oil and gas exploration and ~~production~~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, ~~2017.~~

Certain prior year amounts have been reclassified to conform to the 2017 presentation. On the statements of operations, we reclassified interest cost, expected return on assets, amortization of prior service costs and settlements/curtailments from general and administrative expenses to other non-operating expenses, net in accordance with new accounting rules. See ~~Note 2 Accounting and Disclosure Changes~~ ~~for more information.~~2018.


NOTE 2	ACCOUNTING AND DISCLOSURE CHANGES

Recently ~~Issued Accounting and Disclosure Changes~~

In February 2016, the Financial Accounting Standards Board (FASB) issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB also issued an update to the lease standard providing a practical expedient for the transition of land easements under the new rules. These rules will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with earlier application permitted. We are in the process of cataloging our existing lease contracts to determine the impact of these new rules on our consolidated financial statements and related disclosures.

~~Recently~~ Adopted Accounting and Disclosure Changes

~~In May 2014,~~We adopted the ~~FASB issued~~Financial Accounting Standards Board's new lease accounting rules ~~on the recognition~~(ASC 842), as of ~~revenue, which created Topic 606 (ASC 606), which we adopted on~~ January 1, ~~2018~~2019, using the modified retrospective ~~method. Results for reporting~~approach where the new lease standard is not applied to prior comparative periods, ~~beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and~~which continue to be ~~reported~~presented under ~~the~~ accounting standards in effect prior to adoption. ASC 606 superseded existing revenue recognition requirements under GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those ~~goods or services. We~~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 ~~have an adjustment to opening~~materially impact our consolidated net earnings and had no impact on cash flows or beginning retained ~~earnings upon adoption.~~earnings. The new ~~revenue~~lease standard ~~required certain sales-related costs to be reported as other expense as opposed to being netted against oil~~does not affect our liquidity and ~~gas sales or other revenue.~~has no impact on our debt-covenant calculations under our 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement. See Note ~~11 Revenue Recognition~~12 Leases for more information.

In March 2017, the FASB issued rules requiring employers that sponsor defined benefit plans for pensions and postretirement benefits to present the service cost component of net periodic benefit cost in the same income statement line item as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. Employers are required to present the other components of the net periodic benefit cost separately from the line item that includes the service cost and outside of any subtotal of operating income. We adopted these rules in the first quarter of 2018 with no significant impact on our financial statements. The interest cost, expected return on assets, amortization of prior service costs and settlements/curtailments have been reclassified from general and administrative expense to other non-operating expenses. We elected to apply the practical expedient that permits use of the amounts disclosed for the various components of net periodic benefit cost in the pension and postretirement benefit plans footnote as the basis of the retrospective application.

In May 2017, the FASB issued rules to simplify the guidance on the modification of share-based payment awards. The amendments provide clarity on which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting prospectively. We adopted these rules in the first quarter of 2018 with no impact on our financial statements.

Components of accumulated other comprehensive income (AOCI) are recorded net of related taxes determined using prevailing rates when the components are initially recorded. When tax rates change, a difference can arise between tax amounts recorded to AOCI as compared to the expected tax amount. Our accounting policy is to remove such residual tax effects that may remain in AOCI when the related components are ultimately settled. The change in the U.S. federal corporate tax rate in December 2017 created a residual difference. In February 2018, the FASB issued rules that give entities the option to reclassify this residual difference from AOCI to retained earnings. We early adopted this accounting standard in the first quarter of 2018 without reclassifying this difference.


NOTE 3	OTHER INFORMATION

Cash at March 31, 2019 and ~~cash equivalents consists primarily of highly liquid~~December 31, 2018 included approximately $26 million and $2 million, respectively, that is restricted for capital investments ~~with original maturities of three months or less~~ and ~~are stated at cost, which approximates fair value.~~

distributions to a joint venture (JV) partner.

Other current assets, net as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:


	March 31, 2018		December 31, 2017		March 31,		December 31,
	(in millions)				2019		2018
					(in millions)
Derivative assets					$	79	$	168
Amounts due from joint interest partners	$	76	$	76	68		68
Derivative assets from commodities contracts	44		23
Prepaid expenses	23		19		20		16
Assets held for sale	12		12
Other					—		3
Other current assets, net	$	155	$	130	$	167	$	255

Accrued liabilities as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:


	March 31, 2018		December 31, 2017		March 31,		December 31,
	(in millions)				2019		2018
Derivative liabilities from commodities contracts	$	170	$	154
					(in millions)
Accrued employee-related costs					$	69	$	109
Accrued interest					56		15
Accrued taxes other than on income	143		130		51		38
Accrued interest	67		23
Accrued employee-related costs	52		86
Asset retirement obligation					32		31
Operating lease liability					27		—
Accrued distribution to JV partner					19		—
Other	82		82		31		24
Accrued liabilities	$	514	$	475	$	285	$	217

Other long-term liabilities included asset retirement obligations (ARO) of ~~$407~~$490 million and ~~$403~~$402 million at March 31, ~~2018~~2019 and December 31, ~~2017,~~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, ~~2018~~2019 and ~~2017.~~2018. Interest paid, net of capitalized amounts, totaled approximately ~~$60~~$69 million and ~~$44~~$60 million for the three months ended March 31, 2019 and 2018, ~~and 2017,~~ respectively.

NOTE 4 INVENTORIES

Inventories as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:


					March 31,		December 31,
	March 31, 2018		December 31, 2017		2019		2018
	(in millions)				(in millions)
Materials and supplies	$	54	$	53	$	68	$	65
Finished goods	2		3		3		4
Total	$	56	$	56	$	71	$	69

NOTE 5 DEBT

As of March 31, ~~2018~~2019 and December 31, ~~2017,~~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	Outstanding Principal (in millions)					Interest Rate	Maturity	Security
	March 31, 2018		December 31, 2017					March 31, 2019			December 31, 2018
Credit Agreements
2014 Revolving Credit Facility	$	—	$	363	LIBOR plus 3.25%-4.00% ABR plus 2.25%-3.00%	June 30, 2021	Shared First-Priority Lien	$	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	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	1,000			1,000		LIBOR plus 10.375% ABR plus 9.375%	December 31, 2021	First-Priority Lien
Second Lien Notes
Second Lien Notes	2,248		2,250		8%	December 15, 2022^(b)	Second-Priority Lien	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	100			100		5%	January 15, 2020	Unsecured
5½% Senior Notes due 2021	100		100		5.5%	September 15, 2021	Unsecured	100			100		5.5%	September 15, 2021	Unsecured
6% Senior Notes due 2024	193		193		6%	November 15, 2024	Unsecured	144			144		6%	November 15, 2024	Unsecured
Total	$	4,941	$	5,306
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)	~~Under the terms~~The Second Lien Notes require principal repayments of ~~the indenture,~~ approximately ~~$340~~$324 million ~~needs to be repaid by~~in June 2021, ~~and another $70~~$65 million ~~each by~~in December 2021, $67 million in June 2022 and ~~June~~$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 ~~$275~~$216 million, consisting of ~~$396~~$313 million of a deferred ~~gains~~gain offset by ~~$85~~$97 million of deferred issuance costs and ~~$36 million of~~ original issue discount. The December 31, 2017 net deferred gain and issuance costs were $287 million, consisting of $415 million of deferred gains offset by $92 million of deferred issuance costs and $36 million of original issue discount.discounts.

2014 Revolving Credit Facility

~~In February 2018,~~As of March 31, 2019, we ~~paid $297~~had approximately $256 million of ~~the then outstanding balance on~~available borrowing under our $1 billion ~~senior~~ revolving ~~loan~~credit facility (2014 Revolving Credit Facility) ~~with proceeds from our midstream joint venture with Ares, in accordance with the terms of our credit agreement. See~~ ~~Note 6 Noncontrolling Interests~~ ~~for further information on this joint venture.~~

~~As of March 31, 2018, we had approximately $846 million of available borrowing capacity,~~, before ~~taking into account~~ a $150 million month-end minimum liquidity requirement. ~~The~~Effective May 1, 2019, the borrowing base under this facility was reaffirmed at $2.3 ~~billion in May 2018.~~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, ~~2018~~2019 and December 31, ~~2017,~~2018, we had letters of credit outstanding of approximately ~~$154~~$168 million and ~~$148~~$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 ~~2018,~~2019, we repurchased $2$18 million in ~~aggregate~~ principal amount of our 8% senior secured ~~second-lien~~second lien notes due December 15, 2022 (Second Lien Notes) for ~~$1.6~~$14 million in cash resulting in a ~~$0.4 million pre-tax gain. During April 2018, we repurchased $95 million in aggregate principal amount of our Second Lien Notes for $79 million in cash, resulting in a $15 million~~ pre-tax gain ~~net~~ of ~~a $1~~$6 million, ~~write-off~~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, ~~2018~~2019 and December 31, ~~2017,~~2018, including the fair value of the variable-rate ~~debt,~~portion, was approximately ~~$4.4~~$4.8 billion and ~~$4.8~~$4.5 billion, respectively, compared to a carrying value of approximately ~~$4.9 billion and~~ $5.3 billion ~~respectively.~~in both periods.

Other

~~As of~~At March 31, ~~2018,~~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.

~~For a detailed description of our credit agreements, second lien notes and senior notes, please see our most recent Form 10-K.~~


NOTE 6	~~NONCONTROLLING INTERESTS~~JOINT VENTURES

Noncontrolling Interests

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


							Equity Attributable to Noncontrolling Interest			Mezzanine Equity - Redeemable Noncontrolling Interest			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
	Ares JV			BSP JV			Total			Ares JV
Balance, December 31, 2017	$	—		$	94		94			$	—		$	—		$	94		$	94		$	—
Net income (loss) attributable to noncontrolling interests	1			(4		)	(3		)	14			1			(4		)	(3		)	14
Contributions from noncontrolling interest holders, net	33			—			33			714			33			—			33			714
Distributions to noncontrolling interest holders	(1		)	(14		)	(15		)	(4		)	(1		)	(14		)	(15		)	(4		)
Balance, March 31, 2018	$	33		$	76		$	109		$	724		$	33		$	76		$	109		$	724

Ares Management L.P. (Ares)

~~In February 2018, we entered into a~~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)~~. This JV (Ares JV) holds the Elk Hills power plant, a 550-megawatt natural gas fired power plant, and a 200 million cubic foot per day cryogenic gas processing plant. Through one~~, with ECR's share of ~~our wholly owned subsidiaries, we hold 50% of the Class A common interest and 95.25% of the Class C common interest~~net income (loss) reported 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. We received $750 million~~net income attributable to noncontrolling interests. ECR's redeemable noncontrolling interests are reported in ~~proceeds upon entering into the Ares JV, before $3 million for transaction costs.~~mezzanine equity due to an embedded optional redemption feature.

The fair value of the Class A common interest and Class B preferred interest held by Ares is reported as noncontrolling interest in mezzanine equity and the fair value of the Class C common interest held by Ares is reported in equity on our balance sheet. We have elected to apply the accretion method to adjust the redeemable noncontrolling interest to its redemption price with the measurement adjustment recorded as a component of equity. The measurement adjustment was not material for the three months ended March 31, 2018.

The Ares JV is required to make monthly distributions to the Class B holders. The Class B preferred interest has a deferred payment feature where a portion of the monthly distributions may be deferred for the first three years to the fourth and fifth year. The deferred amounts accrue an additional return. Distributions to the Class B preferred interest holders are reported as a reduction to mezzanine equity on our balance sheet. The Ares JV is also required to distribute its excess cash flow over its working capital requirements, on a pro-rata basis, to the Class C common interests.

We have the option to redeem ECR's Class A and Class B interests, in whole, but not in part, at any time for $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. 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. If we do not exercise our option to redeem at the end of the seven and one-half year period, ECR can monetize its Class A and Class B interests either in a market transaction or through a sale or lease of the Ares JV assets.Benefit Street Partners (BSP)

Our consolidated results reflect the full operations of our ~~Ares~~development JV with ~~Ares'~~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 ~~as a~~in net income attributable to noncontrolling ~~interest~~interests on our ~~statement~~condensed consolidated statements of operations.

~~Benefit Street Partners (BSP)~~

~~In February 2017, we entered into a joint venture with~~ BSP ~~(BSP JV) where BSP will contribute up to $250~~contributed $49 million subject to agreement of the parties, in exchange for a preferred interest in the BSP JV. The funds contributed by BSP were used to develop certain of our oil and gas properties. BSP is entitled to preferential distributions and, if BSP receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. BSP funded two $50 million tranches in March and July 2017, before a $2 million total issuance fee. In 2017, the $98 million net proceeds were used to fund capital investments of $96 million and the remainder was used for hedging activities. The BSP JV holds net profits interests (NPI) in existing and future cash flow from certain of our properties and the proceeds from the NPIs are used by the BSP JV to (1) pay quarterly minimum distributions to BSP, (2) pay for development costs within the project area, upon mutual agreement between members, and (3) make distributions to BSP until the predetermined threshold is achieved.

~~Our consolidated results reflect the full operations of our BSP JV, with BSP's share of net income being reported as a noncontrolling interest on our statement of operations.~~

~~Macquarie Infrastructure and Real Assets Inc. (MIRA)~~

Our consolidated results only include our working interest share in a joint venture we entered into with Macquarie Infrastructure and Real Assets Inc. (MIRA) in April 2017. Subject to the agreement of the parties, MIRA will invest up to $300 million to develop certain of our oil and gas properties in exchange for a 90% working interest in the related properties (MIRA JV). MIRA will fund 100% of the development cost of such properties. Our 10% working interest increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. MIRA initially committed $160 million, which is intended to be invested over two years. Of the committed amount, MIRA contributed $58 million for drilling projects in 2017 and is expected to contribute $75 million in 2018, of which $22 million was funded in the first quarter of ~~2018.~~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, ~~2018~~2019 and December 31, ~~2017~~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 ~~on our balance sheet~~ would not be material to our consolidated financial position or results of operations.

We ~~our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might incur in~~remain subject to examination by the ~~future in connection with~~IRS for calendar years 2016 and 2017. We remain subject to examination by the Spin-off, purchases and other transactions that they have entered into with us. These indemnities include indemnities made to Occidental against certain tax-related liabilities that may be incurred by Occidental relating tostate of California for the ~~Spin-off and liabilities related to operation of our business while it was still owned by Occidental. As of March~~years ended December 31, ~~2018, we are not aware of material indemnity claims pending or threatened against the company.~~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 ~~while maintaining~~and interest-rate movements. These derivatives are intended to help us maintain adequate liquidity and ~~improving~~improve our ability to comply with the covenants of our Credit Facilities in case of price deterioration. We will continue to be strategic and opportunistic in implementing our hedging program as market conditions permit. Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty.

Commodity Price Risk

~~As of March 31, 2018, we~~We did not have any commodity derivatives designated as ~~hedges. Unless otherwise indicated, we use~~hedges as of and during the ~~term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not necessarily accounted for as cash-flow or fair-value hedges.~~three months ended March 31, 2019 and 2018. As part of our hedging program, we ~~entered into a number of derivative transactions that resulted in~~held the following Brent-based crude oil contracts as of March 31, ~~2018:~~2019:


	Q2 2018		Q3 2018		Q4 2018		Q1 2019		Q2 2019		Q3 2019		Q4 2019		FY 2020		Q2 2019		Q3 2019		Q4 2019		Q1 2020
Sold Calls:
Barrels per day	6,168		6,127		16,086		16,057		6,023		991		961		503
Weighted-average price per barrel	$	60.24	$	60.24	$	58.91	$	65.75	$	67.01	$	60.00	$	60.00	$	60.00

Purchased Calls:
Barrels per day	—		—		—		2,000		—		—		—		—		5,000		—		—		—
Weighted-average price per barrel	$	—	$	—	$	—	$	71.00	$	—	$	—	$	—	$	—	$	68.45	$	—	$	—	$	—

Purchased Puts:
Barrels per day	1,168		6,127		1,086		24,057		11,023		991		961		503		40,000		40,000		35,000		10,000
Weighted-average price per barrel	$	45.83	$	61.47	$	45.85	$	60.00	$	60.05	$	45.85	$	45.85	$	43.91	$	69.75	$	73.13	$	75.71	$	75.00

Sold Puts:
Barrels per day	29,000		24,000		19,000		25,000		5,000		—		—		—		35,000		40,000		35,000		10,000
Weighted-average price per barrel	$	45.00	$	46.04	$	45.00	$	49.00	$	50.00	$	—	$	—	$	—	$	55.71	$	57.50	$	60.00	$	60.00

Swaps:
Barrels per day	44,350		19,000⁽¹⁾		19,000⁽¹⁾		7,000⁽²⁾		—		—		—		—
Weighted-average price per barrel	$	60.00	$	60.13	$	60.13	$	67.71	$	—	$	—	$	—	$	—


~~Note:~~	~~Additional hedges for 2019 were put in place after March 31, 2018 that are not included in the table above.~~


~~(1)~~	~~Certain of our counterparties have options to increase swap volumes by up to 29,000 barrels per day at a weighted-average Brent price of $60.50 for the second half of 2018.~~


~~(2)~~	~~Certain of our counterparties have options to increase swap volumes by up to 5,000 barrels per day at a weighted-average Brent price of $70.00 for the first quarter of 2019.~~

~~As of March 31, 2018, a small portion of the~~The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the ~~table~~ above ~~were entered into by the~~table. The BSP JV ~~including all of the 2020 hedges. This joint venture~~ also entered into natural gas swaps for insignificant volumes for periods through ~~July 2020.~~

May 2021. The ~~outcomes~~hedges entered into by the BSP JV could affect the timing of the ~~derivative positions are as follows:~~

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

~~Purchased calls – we receive 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.~~

~~From time to time, we may use combinations of these positions to increase the efficacy of our hedging program.~~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 ~~commodity derivatives~~derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are ~~all~~ 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, ~~2018~~2019 and December 31, ~~2017~~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

March 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
Commodity Contracts Other current assets $ 52
$ (8 ) $ 44
Commodity Contracts Other assets 7
—
7

Liabilities
Commodity Contracts Accrued liabilities (178 ) 8
(170 )
Commodity Contracts Other long-term liabilities (7 ) —
(7 )
Total derivatives $ (126 ) $ —
$ (126 )



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

December 31, 2017
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
Commodity Contracts Other current assets $ 39
$ (16 ) $ 23
Commodity Contracts Other assets 1
—
1

Liabilities
Commodity Contracts Accrued liabilities (170 ) 16
(154 )
Commodity Contracts Other long-term liabilities (3 ) —
(3 )
Total derivatives $ (133 ) $ —
$ (133 )

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 ~~when such shares~~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 ~~the~~ 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, ~~2018~~2019 and ~~2017:~~2018:

Three months ended
March 31,
2018 2017
(in millions, except per-share amounts)
Basic EPS calculation
Net income $ 9
$ 52
Net (income) loss attributable to noncontrolling interest (11 ) 1
Net (loss) income attributable to common stock (2 ) 53
Less: net income (loss) allocated to participating securities —
(1 )
Net (loss) income available to common stockholders $ (2 ) $ 52
Weighted-average common shares outstanding - basic 44.2
42.3
Basic EPS $ (0.05 ) $ 1.23

Diluted EPS calculation
Net income $ 9
$ 52
Net (income) loss attributable to noncontrolling interest (11 ) 1
Net (loss) income attributable to common stock (2 ) 53
Less: net income (loss) allocated to participating securities —
(1 )
Net (loss) income available to common stockholders $ (2 ) $ 52
Weighted-average common shares outstanding - basic 44.2
42.3
Dilutive effect of potentially dilutive securities —
0.3
Weighted-average common shares outstanding - diluted 44.2
42.6
Diluted EPS $ (0.05 ) $ 1.22
Weighted-average anti-dilutive shares 2.5
1.5



	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,										Three months ended March 31,
	2018					2017					2019					2018
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)										(in millions)
Service cost	$	—		$	1	$	—		$	1	$	—		$	1	$	—		$	1
Interest cost	1			1		1			1		1			1		1			1
Expected return on plan assets	(1		)	—		(1		)	—		(1		)	—		(1		)	—
Recognized actuarial loss											1			—		—			—
Settlement loss	2			—		3			—		—			—		2			—
Total	$	2		$	2	$	3		$	2	$	1		$	2	$	2		$	2

~~During~~

We did not contribute to our defined benefit pension plan in the three months ended March 31, ~~2018~~2019 and ~~2017, we~~ contributed $1 million ~~and $4 million, respectively, to our defined benefit pension plans.~~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 ~~2018.~~2019. The 2018 ~~and 2017 settlements were~~settlement loss, which was reclassified from accumulated other comprehensive income, was associated with early retirements.

NOTE 11 REVENUE RECOGNITION

We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers, which we adopted on January 1, 2018, using the modified retrospective method, which was applied to all contracts that were not completed as of that date. Prior period results are not adjusted and continue to be reported under the accounting standards in effect for the prior period. The new standard did not affect the timing of our revenue recognition and did not impact net income; accordingly, we did not record an adjustment to the opening balance of retained earnings.

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 and sales of power.~~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. ~~In certain instances, transportation~~Transportation and processing fees ~~are~~ incurred by us prior to control being transferred to ~~customers. These costs were previously offset against oil and gas sales. Upon adoption of ASC 606, we~~customers are ~~recording these costs~~recorded as a component of other expenses, ~~net.~~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 ~~which~~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 ~~our~~the Elk Hills power plant that is not used in our operations is sold to the ~~grid through~~ wholesale power ~~marketing entities~~market and to a utility under a power purchase and ~~sale~~sales agreement, which includes a capacity payment. Revenue is recognized when obligations under the terms of ~~a contract~~contracts with our ~~customer~~customers are satisfied; generally, this occurs upon delivery of the electricity. We report electricity sales as other ~~revenue.~~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 ~~the delivery of our product.~~delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on ~~seasonality, which is consistent with how we earn the capacity payment.~~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, ~~revenues represent~~trading and other revenue primarily includes our activities associated with storing, transporting and ~~transporting~~marketing our production and other marketing revenue. With respect to our natural gas liquids, we may enter into contracts, typically with durations of one year or less, for refrigerated storage services that assist us in managing the seasonality of our products.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.~~revenue on our condensed consolidated statements of operations.

Disaggregation of Revenue

The following table provides disaggregated revenue for the three months ended March 31, ~~2018 (in millions):~~2019 and 2018:


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

~~The impact~~

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 ~~adoption~~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 ~~606~~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 ~~operations~~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 ~~as follows (in millions):~~

As Reported
ASC 606

Previous
U.S. GAAP
Change
REVENUES AND OTHER
Oil and gas sales $ 575
$ 568
$ 7
Net derivative losses (38 ) (38 ) —
Other revenue 72
37
35
Total revenues and other 609
567
42

COSTS AND OTHER
Production costs 212
212
—
General and administrative expenses 63
63
—
Depreciation, depletion and amortization 119
119
—
Taxes other than on income 38
38
—
Exploration expense 8
8
—
Other expenses, net 61
19
42
Total costs and other 501
459
42
OPERATING (LOSS) INCOME 108
108
—

NON-OPERATING (LOSS) INCOME
Interest and debt expense, net (92 ) (92 ) —
Other non-operating expenses (7 ) (7 ) —
(LOSS) INCOME BEFORE INCOME TAXES 9
9
—
Income tax benefit —
—
—
NET (LOSS) INCOME 9
9
—
Net (income) loss attributable to noncontrolling interests (11 ) (11 ) —
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (2 ) $ (2 ) $ —
not significant.

~~The adoption of ASC 606 did not have an impact on our condensed consolidated balance sheets as of March 31, 2018 and December 31, 2017.~~

NOTE 1213 INCOME TAXES

For the three months ended March 31, ~~2018~~2019 and ~~2017,~~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 ~~is primarily related~~presented includes changes to ~~an increase in~~maintain our ~~valuation allowance based on the expectation of a tax loss for the year. Given our recent and anticipated future earnings trends, we have recorded a~~ full valuation allowance against our net deferred tax ~~asset~~assets given our recent and ~~do not~~anticipated future earnings trends. We believe ~~any~~that there is a reasonable possibility that some or all of ~~our valuation~~this allowance ~~as of March 31, 2018 will~~could be released ~~within~~in the ~~next 12 months. The~~foreseeable future. However, the amount of the net deferred tax assets considered realizable ~~could however be adjusted if estimates change.~~

~~The Tax Cuts and Jobs Act, signed into law~~depends on ~~December 22, 2017, included significant changes~~the level of profitability that we are able to corporate tax provisions such as a reduction in the corporate tax rate, limitations on certain corporate deductions and favorable capital recovery provisions. The California Franchise Tax Board released its summary of Federal Income Tax Changes for 2017 on April 19, 2018, which identifies how these federal changes interact with California law. California law was not conformed to the corporate provisions which were the most significant to our business.

~~NOTE 13 SUBSEQUENT EVENTS~~

On April 2, 2018, we acquired an office building in Bakersfield, California for $48.4 million. We currently have close to 500 employees in nine different locations in Bakersfield across multiple leases. We expect that the new building will create significant value for us by bringing all of our Bakersfield employees together into a single location over the next 12 to 18 months, which will increase the efficiency, effectiveness and collaboration of these employees. We also plan on moving our backbone infrastructure, which is also in several different buildings, including our data center and records department, into the building within a year. For the initial eight months, a former owner of the building will occupy most of the space as a tenant, from which we expect to generate rental income of approximately $4 million in 2018. In December 2018, this tenant will downsize the space they are leasing, with a corresponding reduction in rent, until December 2022. The building is large enough to house all of our Bakersfield employees and still allow us to lease out space to other tenants after December 2018 to generate additional rental income.

On April 9, 2018, we acquired the remaining working, surface and mineral interests in the Elk Hills field from Chevron U.S.A., Inc. (Chevron) for approximately $510 million consisting of $460 million in cash and 2.85 million in unregistered shares of CRC common stock (the Elk Hills transaction). After the transaction, we hold in fee simple a 100% working interest, a 100% net revenue interest and all of the surface land in the Elk Hills field. The effective date of the transaction was April 1, 2018. We also entered into a Registration Rights Agreement pursuant to which we agreed to register for resale the shares issued to Chevron within two business days following the filing of this Form 10-Q for the quarterly period ended March 31, 2018. The Registration Rights Agreement limits Chevron’s ability to resell shares as follows: (1) up to 1 million shares in the first 30 days following effectiveness of the registration statement, (2) up to 1 million additional shares (plus the balance of any unsold shares in the first 30-day period) in the 30 days thereafter, and (3) any remaining shares thereafter.

As part of the Elk Hills transaction, Chevron reduced its royalty interest in one of our oil and gas properties by half and extended, by two years to the end of 2020, the time frame to invest the remainder of our capital commitment on that property. As of March 31, 2018, the remaining commitment was approximately $58 million. Any deficiency in meeting this capital investment obligation would still need to be paid in cash. We expect to fulfill the capital investment requirement within the extended period. In addition, the parties mutually agreed to release each other from pending claims with respect to Elk Hills.actually achieve.

NOTE 14 ~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~ASSET DIVESTITURE

~~Our Credit Facilities and Second Lien Notes are guaranteed both fully and unconditionally and jointly and severally by our material wholly owned subsidiaries (Guarantor Subsidiaries). Certain~~On May 1, 2019, we sold 50% of our ~~subsidiaries do not guarantee our Credit Facilities~~working interest and ~~Second Lien Notes (Non-Guarantor Subsidiaries) either because they hold assets that are less than 1%~~transferred operatorship in certain zones of our Lost Hills field, located in the San Joaquin basin, for total ~~consolidated assets or because they are not considered~~consideration in excess of $200 million, consisting of approximately $168 million in cash and a ~~"subsidiary" under the applicable financing agreement.~~carried 200-well development program to be drilled through 2023 with an estimated minimum value of $35 million. The following condensed consolidating balance sheets at March 31, 2018 and December 31, 2017, condensed consolidating statements of operations and statements of cash flows for the three months ended March 31, 2018 and 2017 reflect the condensed consolidating financial information ofproceeds were used to pay down 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 CRC on a consolidated basis.2014 Revolving Credit Facility.

~~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
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated
As of March 31, 2018 (in millions)
Total current assets $ 491
$ 414
$ 51
$ (7 ) $ 949
Total property, plant and equipment, net 23
5,153
538
—
5,714
Investments in consolidated subsidiaries 5,050
95
—
(5,145 ) —
Other assets —
22
14
—
36
TOTAL ASSETS $ 5,564
$ 5,684
$ 603
$ (5,152 ) $ 6,699

Total current liabilities 125
680
8
(7 ) 806
Long-term debt 4,941
—
—
—
4,941
Deferred gain and issuance costs, net 275
—
—
—
275
Other long-term liabilities 153
448
6
—
607
Amounts due to (from) affiliates 833
(833 ) —
—
—
Mezzanine equity —
—
724
—
724
Total equity (763 ) 5,389
(135 ) (5,145 ) (654 )
TOTAL LIABILITIES AND EQUITY $ 5,564
$ 5,684
$ 603
$ (5,152 ) $ 6,699

As of December 31, 2017
Total current assets $ 13
$ 464
$ 12
$ (6 ) $ 483
Total property, plant and equipment, net 24
5,580
92
—
5,696
Investments in consolidated subsidiaries 5,105
606
—
(5,711 ) —
Other assets —
27
1
—
28
TOTAL ASSETS $ 5,142
$ 6,677
$ 105
$ (5,717 ) $ 6,207

Total current liabilities 122
613
3
(6 ) 732
Long-term debt 5,306
—
—
—
5,306
Deferred gain and issuance costs, net 287
—
—
—
287
Other long-term liabilities 154
445
3
—
602
Amounts due to (from) affiliates 87
(87 ) —
—
—
Total equity (814 ) 5,706
99
(5,711 ) (720 )
TOTAL LIABILITIES AND EQUITY $ 5,142
$ 6,677
$ 105
$ (5,717 ) $ 6,207

Condensed Consolidating Statement of Operations
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated

For the three months ended March 31, 2018 (in millions)
Total revenues and other $ 1
$ 585
$ 65
$ (42 ) $ 609
Total costs and other 44
460
39
(42 ) 501
Non-operating loss (98 ) (1 ) —
—
(99 )
NET (LOSS) INCOME (141 ) 124
26
—
9
Net income attributable to noncontrolling interests —
—
(11 ) —
(11 )
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (141 ) $ 124
$ 15
$ —
$ (2 )

For the three months ended March 31, 2017
Total revenues and other $ —
$ 589
$ 1
$ —
$ 590
Total costs and other 53
420
2
—
475
Non-operating (loss) income (81 ) 18
—
—
(63 )
NET (LOSS) INCOME (134 ) 187
(1 ) —
52
Net loss attributable to noncontrolling interest —
—
1
—
1
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (134 ) $ 187
$ —
$ —
$ 53

Condensed Consolidating Statement of Cash Flows
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated

For the three months ended March 31, 2018 (in millions)
Net cash (used) provided by operating activities $ (154 ) $ 327
$ 27
$ —
$ 200
Net cash used in investing activities (1 ) (136 ) (1 ) —
(138 )
Net cash provided (used) by financing activities 633
(199 ) (22 ) —
412
Increase (decrease) in cash and cash equivalents 478
(8 ) 4
—
474
Cash and cash equivalents—beginning of period 7
8
5
—
20
Cash and cash equivalents—
end of period
$ 485
$ —
$ 9
$ —
$ 494

For the three months ended March 31, 2017
Net cash (used) provided by operating activities $ (139 ) $ 274
$ (2 ) $ —
$ 133
Net cash (used) provided by investing activities (1 ) 1
—
—
—
Net cash provided (used) by financing activities 140
(284 ) 49
—
(95 )
(Decrease) increase in cash and cash equivalents —
(9 ) 47
—
38
Cash and cash equivalents—beginning of period —
12
—
—
12
Cash and cash equivalents—
end of period
$ —
$ 3
$ 47
$ —
$ 50


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 ~~generally~~ as a result of numerous market-related variables such as consumption patterns; inventory levels; global and local economic conditions; the actions of the Organization of the Petroleum Exporting Countries (OPEC) and other producers and governments; actual or threatened disruptions in production, refining and processing; currency exchange rates; worldwide drilling and exploration activities; the effects of conservation, weather, geophysical and technical limitations; technological advances; transportation and storage capacity, bottlenecks and costs in producing areas; alternative energy sources; regional market conditions; and other matters affecting the supply and demand dynamics for our products; as well as the effect of changes in these variables on market perceptions.variables. These and other factors make it impossible to predict realized prices reliably.

~~Much of the global exploration and production industry has been challenged~~Global oil prices gradually increased in the ~~low-commodity~~first quarter of 2019 from the decline that began late in the fourth quarter of 2018. However, the average Brent crude oil price ~~cycle~~ in ~~recent years, putting pressure on~~ the ~~industry's ability~~first quarter of 2019 did not return to ~~generate positive cash flow~~its previous 2018 highs and ~~access capital. Global oil~~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 2018 compared to the same period of 2017. Prices for natural gas liquids (NGLs) have improved relative to crude oil prices due to tighter local supplies and higher contract prices across the NGL spectrum. Natural gas prices in the U.S. were lower in the first quarter of 20182019 than the comparable period of ~~2017~~2018 largely due to higher ~~natural gas production.~~winter demand in 2019.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:


	Three months ended March 31,				Three months ended March 31,
	2018		2017		2019		2018
Brent oil ($/Bbl)	$	67.18	$	54.66	$	63.90	$	67.18
WTI oil ($/Bbl)	$	62.87	$	51.91	$	54.90	$	62.87
NYMEX gas ($/MMBtu)	$	2.87	$	3.26	$	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 ~~72%~~73% of the oil consumed in ~~2017~~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. ~~Additionally, our differentials~~

Price realizations for NGLs improved ~~against Brent during 2017, continuing into the early part of 2018, in response to strong demand for California crude oil as well~~ as a ~~decline~~percentage of Brent due to higher valued local sales in ~~California crude oil production.~~

~~Prices and differentials for NGLs~~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 ~~well as~~storage capacity and the availability of transportation capacity from producing areas. Transportation capacity influences prices because California imports ~~about~~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 ~~since we can deliver our gas for~~due to lower transportation ~~costs. Due to~~costs on the delivery of our ~~much lower natural gas production compared to our oil production, the changes~~gas. Changes in natural gas prices have a smaller impact on our operating ~~results.~~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.~~results due to higher revenue. Conversely, lower natural gas prices lower the operating costs but, generally, have a net negative effect on our ~~results, but lower the cost of our steamflood projects and power generation.~~results.

Our earnings are also affected by the performance of our complementary processing and ~~power generation~~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 ~~grid~~wholesale power market and a utility under a power purchase and sales agreement ~~that~~expiring in December 2020, which includes a capacity payment. The price obtained for excess power impacts our earnings but generally by an insignificant amount.

Tariffs of 25% for steel and 10% for aluminum on foreign imports from certain countries were made effective on March 23, 2018. We procure tubular goods and equipment from multiple vendors. We do not expect these tariffs to have a material impact on our costs.

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 ~~necessarily~~ accounted for as cash-flow or fair-value hedges.

We respond to economic conditions by adjusting the amount and allocation of our capital program ~~aligning the size of our workforce with our level of activity and~~while continuing to identify efficiencies and cost savings. The reductions in our capital program in 2015 and 2016 negatively impacted our 2017 production levels. With our increased capital program in 2017, our oil production flattened. With our 2018 program, even excluding acquisitions, we expect to achieve oil production growth in the second half of the year and exit the year with higher production than the beginning of the year. Volatility in oil prices may materially affect the quantities of oil and gas reserves we can economically produce over the longer term.

~~Seasonality~~

~~While certain aspects of our operations are affected by seasonal factors, such as electricity costs, overall, seasonality is not a material driver of changes in our quarterly results during the year.~~

~~Joint Ventures~~

~~Exploration and Development Joint Ventures~~

In line with our strategy, we have entered into a number of joint ventures (JVs) which 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 February 2017, we entered into a joint venture with Benefit Street Partners (BSP) where BSP will contribute up to $250 million, subject to agreement of the parties, in exchange for a preferred interest in the BSP joint venture (BSP JV). The funds contributed by BSP were used to develop certain of our oil and gas properties. BSP is entitled to preferential distributions and, if BSP receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. BSP funded two $50 million tranches in March and July 2017, before a $2 million total issuance fee. In 2017, the $98 million net proceeds were used to fund capital investments of $96 million and the remainder was used for hedging activities. We expect funding of the third tranche of BSP capital in the second quarter of 2018. The BSP JV holds net profits interests (NPI) in existing and future cash flow from certain of our properties and the proceeds from the NPIs are used by the BSP JV to (1) pay quarterly minimum distributions to BSP, (2) pay for development costs within the project area, upon mutual agreement between members, and (3) make distributions to BSP until the predetermined threshold is achieved. Our consolidated results reflect the full operations of our BSP JV, with BSP's share of net income and net assets being shown separately as a noncontrolling interest in the accompanying consolidated statements of operations and consolidated balance sheets, respectively.

In April 2017, we entered into a JV with Macquarie Infrastructure and Real Assets Inc. (MIRA) under which MIRA will invest up to $300 million, subject to agreement of the parties, to develop certain of our oil and gas properties in exchange for a 90% working interest in the related properties (MIRA JV). MIRA will fund 100% of the development cost of such properties. Our 10% working interest increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. MIRA initially committed $160 million, which is intended to be invested over two years. Of the committed amount, MIRA contributed $58 million for drilling projects in 2017 and is expected to contribute $75 million in 2018, of which $22 million was funded in the first quarter of 2018. Our consolidated results reflect only our working interest share in our MIRA JV.

We have also entered into a number of exploration joint ventures where our partners carry all or substantially all of our exploration costs. These JV partners have committed capital of approximately $30 million and could provide an additional $45 million in capital if certain milestones are met.

~~Midstream Joint Venture~~

In February 2018, we entered into a midstream JV with ECR Corporate Holdings L.P. (ECR), a portfolio company of Ares Management L.P. (Ares). This JV (Ares JV) holds the Elk Hills power plant, a 550-megawatt natural gas fired power plant, and a 200 million cubic foot per day cryogenic gas processing plant. Through one of our wholly owned subsidiaries, 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. We received $750 million in proceeds upon entering into the Ares JV, before $3 million of transaction costs.

~~Our consolidated results reflect the full operations of our Ares JV, with Ares' share of net income being reported as a noncontrolling interest on our statement of operations.~~

~~Private Placement~~

In February 2018 and in connection with the formation of the Ares JV, an Ares-led investor group purchased approximately 2.3 million shares of our common stock in a private placement for an aggregate purchase price of $50 million.

~~Acquisitions and Divestitures~~

~~In February 2017, we divested non-core assets resulting in $32 million of proceeds and a $21 million gain.~~

Operations

We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. We ~~believe we~~ are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately ~~2.3~~2.2 million net mineral acres, approximately 60% of which ~~we hold~~is held in fee and ~~approximately~~over 15% ~~of which~~ is held by production. Our oil and gas leases have primary terms ranging from one to ten ~~years, which~~years. Once production commences, the leases are extended through the end of ~~production once it commences.~~their producing life. We also own or control a network of ~~strategically placed~~integrated infrastructure that ~~is integrated with, and complementary to,~~complements our operations including gas plants, oil and gas gathering systems, power plants and other related ~~assets, which we use to~~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. ~~The~~These contracts represented ~~over~~approximately 15% of our production for the quarter ended March 31, ~~2018.~~2019.

In ~~addition, in~~ line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under ~~the PSCs~~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 ~~PSCs.~~PSC-type contracts. This difference in reporting full operating costs but only our net share of production equally inflates our revenue and operating costs ~~per barrel, with an equal corresponding increase in revenues, with~~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 ~~developing~~ real estate development initiatives include exploring ~~opportunities to use our land for~~ renewable energy opportunities on our land such as solar energy ~~projects;~~projects, agricultural activities ~~such~~(such as the production of fruits and ~~nuts;~~nuts) and other commercial real ~~estate.~~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

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.

Fixed and Variable Costs

Our ~~total~~ production costs ~~consist of~~include variable costs that ~~tend to vary depending on~~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. ~~While a~~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,~~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, ~~2018~~2019 and ~~2017:~~2018:


	Three months ended March 31,		Three months ended March 31,
	2018	2017	2019	2018
Oil (MBbl/d)
San Joaquin Basin	49	54	55	49
Los Angeles Basin	24	27	25	24
Ventura Basin	4	5	4	4
Sacramento Basin	—	—
Total	77	86	84	77
NGLs (MBbl/d)
San Joaquin Basin	15	15	14	15
Los Angeles Basin	—	—
Ventura Basin	1	1	1	1
Sacramento Basin	—	—
Total	16	16	15	16
Natural gas (MMcf/d)
San Joaquin Basin	143	141	165	143
Los Angeles Basin	1	1	2	1
Ventura Basin	7	8	7	7
Sacramento Basin	31	31	28	31
Total	182	181	202	182

Total Production (MBoe/d)^(a)	123	132
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.


~~(a)~~	Natural gas volumes have been converted to Boe based on the equivalence of energy content ~~between~~of six ~~Mcf~~thousand cubic feet of natural gas ~~and~~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, ~~2018~~2019 and ~~2017:~~2018:

Three months ended
March 31,
2018 2017
Oil prices with hedge ($ per Bbl) $ 62.77
$ 50.24

Oil prices without hedge ($ per Bbl) $ 67.26
$ 50.40
NGLs prices ($ per Bbl) $ 43.13
$ 34.33
Natural gas prices ($ per Mcf)^(a)
$ 2.81
$ 2.90



	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%


~~(a)~~	For the three months ended March 31, 2018, the realized gas price was impacted by the adoption of new accounting rules on revenue recognition by $0.28 and would have been $2.53 per Mcf under prior accounting standards.

~~The following table presents our average price realizations as a percentage of Brent, WTI and NYMEX for the three months ended March 31, 2018 and 2017:~~

Three months ended
March 31,
2018 2017
Oil with hedge as a percentage of Brent 93 % 92 %
Oil with hedge as a percentage of WTI 100 % 97 %

Oil without hedge as a percentage of Brent 100 % 92 %
Oil without hedge as a percentage of WTI 107 % 97 %
NGLs as a percentage of Brent 64 % 63 %
NGLs as a percentage of WTI 69 % 66 %
Natural gas as a percentage of NYMEX^(a)
98 % 89 %


~~(a)~~	For the three months ended March 31, 2018, the gas price realization as a percentage of NYMEX was impacted by the adoption of new accounting rules on revenue recognition and would have been 88% under prior accounting standards.

Balance Sheet Analysis

The changes in our balance sheet from December 31, ~~2017~~2018 to March 31, ~~2018~~2019 are discussed below:


	March 31, 2018			December 31, 2017			March 31, 2019			December 31, 2018
	(in millions)						(in millions)
Cash and cash equivalents	$	494		$	20
Cash							$	43		$	17
Trade receivables	$	244		$	277		$	296		$	299
Inventories	$	56		$	56		$	71		$	69
Other current assets, net	$	155		$	130		$	167		$	255
Property, plant and equipment, net	$	5,714		$	5,696		$	6,548		$	6,455
Other assets	$	36		$	28		$	105		$	63
Current maturities of long-term debt							$	100		$	—
Accounts payable	$	292		$	257		$	304		$	390
Accrued liabilities	$	514		$	475		$	285		$	217
Long-term debt	$	4,941		$	5,306		$	5,169		$	5,251
Deferred gain and issuance costs, net	$	275		$	287		$	203		$	216
Other long-term liabilities	$	607		$	602		$	692		$	575
Mezzanine equity	$	724		$	—		$	766		$	756
Equity attributable to common stock	$	(763	)	$	(814	)	$	(426	)	$	(361	)
Equity attributable to noncontrolling interests	$	109		$	94		$	137		$	114

Cash ~~and cash equivalents~~ at March 31, 2019 and December 31, 2018 included ~~the remaining proceeds from the issuance of the preferred~~approximately $26 million and ~~common member interests in the Ares JV, after the pay off of $297~~$2 million, ~~on the then outstanding balance of our 2014 Revolving Credit Facility.~~respectively, which is restricted for capital investments and distributions to BSP. See Liquidity and Capital Resources for ~~additional discussion of changes in~~our cash ~~and cash equivalents.~~flow analysis.

The decrease ~~in trade receivables was largely the result of lower production volumes partially offset by higher prices in the first quarter of 2018 compared to the fourth quarter of 2017. The increase~~ 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 (DD&A).~~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 ~~increase~~reduction in accounts payable for the quarter ended March 31, ~~2018 was primarily~~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 ~~gradual ramp up~~current portion of ~~activity. The increase in accrued liabilities was primarily due to higher property taxes, derivative obligations and obligations related to~~ our ~~joint ventures, as well as higher accrued interest on our Second Lien Notes due to~~operating lease liability resulting from the ~~timing~~adoption of ~~payments.~~new lease accounting rules. These increases were partially offset by ~~a decrease in~~lower accrued employee-related costs, which primarily reflected employee bonus payments in the first quarter of ~~2018. The decrease in~~2019.

Other long-term ~~debt primarily~~liabilities reflected the ~~pay off~~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 ~~outstanding balance on our 2014 Revolving Credit Facility and repurchases of our Second Lien Notes. The decrease in deferred gain and issuance costs,~~ net ~~reflected~~loss for the ~~amortization of deferred gains, partially offset by the amortization of deferred issuance costs.~~period.

~~Mezzanine equity reflected the value of the noncontrolling interest in our Ares JV held by ECR, which has an embedded optional redemption feature.~~ The increase in equity attributable to ~~common stock primarily~~noncontrolling interests reflected contributions made by the ~~issuance of common stock in a private placement. Equity attributable to noncontrolling interest primarily reflected the contribution from Ares,~~BSP JV, partially offset by distributions payable to and net loss allocated to the Ares and ~~BSP.~~BSP JVs during the period. See Item 1 – Financial Statements – Note 6 Joint Ventures for more information.

~~Statement~~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,				Three months ended March 31,
	2018		2017		2019		2018
Production costs	$	19.08	$	17.70	$	19.46	$	19.08
Production costs, excluding effects of PSC contracts^(a)	$	17.47	$	16.66
Production costs, excluding effects of PSC-type contracts^(a)					$	18.01	$	17.47
Field general and administrative expenses^(b)	$	0.72	$	0.76	$	1.25	$	0.72
Field depreciation, depletion and amortization^(b)	$	9.63	$	11.07	$	9.27	$	9.90
Field taxes other than on income^(b)	$	2.70	$	2.27	$	2.67	$	2.70


(a)	As described in the Operations section, the reporting of our ~~PSC-like~~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. ~~The~~These amounts represent ~~the~~our production costs ~~for the company~~ after adjusting for this difference.


(b)	Excludes corporate ~~amounts.~~expenses.

Consolidated Results of Operations

The following represents key operating data for consolidated operations for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:


	Three months ended March 31,						Three months ended March 31,
	2018			2017			2019			2018
	(in millions)						(in millions)
Oil and gas sales^(a)	$	575		$	487		$	601		$	575
Net derivative (losses) gains	(38		)	73
Net derivative loss							(89		)	(38		)
Other revenue^(a)	72			30			178			72
Production costs	(212		)	(211		)	(233		)	(212		)
General and administrative expenses^(b)	(63		)	(63		)	(83		)	(63		)
Depreciation, depletion and amortization	(119		)	(140		)	(118		)	(119		)
Taxes other than on income	(38		)	(33		)	(41		)	(38		)
Exploration expense	(8		)	(6		)	(10		)	(8		)
Other expenses, net^(a)	(61		)	(22		)	(148		)	(61		)
Interest and debt expense, net	(92		)	(84		)	(100		)	(92		)
Net gains on early extinguishment of debt	—			4
Gains on asset divestitures	—			21
Net gain on early extinguishment of debt							6			—
Other non-operating expenses	(7		)	(4		)	(7		)	(7		)
Income before income taxes	9			52
Income tax benefit	—			—
Net income	9			52
Net (income) loss attributable to noncontrolling interests	(11		)	1
Net (loss) income attributable to common stock	$	(2	)	$	53
(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 (loss)	$	8		$	(43	)
Adjusted net income							$	31		$	8
Adjusted EBITDAX	$	250		$	200		$	301		$	250
Effective tax rate	—		%	—		%	—		%	—		%

~~(a)~~

~~We adopted the new revenue recognition standard on January 1,~~

Three months ended March 31, 2019 vs. 2018 which required certain sales-related costs to be reported as expense as opposed to being netted against revenue. The adoption of this standard does not affect net income. Results for reporting periods beginning after January 1, 2018 are presented under the new accounting standard while prior periods are not adjusted and continue to be reported under accounting standards in effect for the prior period. Under prior accounting standards total oil and gas sales would have been $568 million, other revenue would have been $37 million and other expenses, net would have been $19 million. See ~~Note 11 Revenue Recognition~~ ~~for more information.~~

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	)	$	—

~~(b)~~

Certain pension benefit costs of $4 million have been reclassified to other non-operating expenses for the quarter ended March 31, 2017 to conform to the current year presentation in accordance with new accounting rules adopted during the period related to net periodic benefit costs for pensions and postretirement benefits. See ~~Significant Accounting and Disclosure Changes~~ ~~for more information.~~

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 ~~derivatives~~derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) ~~which~~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~~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 ~~Adjusted EBITDAX~~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. ~~While Adjusted EBITDAX~~Although this is a non-GAAP measure, the amounts included in the calculation ~~of Adjusted EBITDAX~~ 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 ~~this measure~~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. Certain items excluded from Adjusted EBITDAX 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. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

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

Three months ended
March 31,
2018 2017
(in millions)
Net (loss) income attributable to common stock $ (2 ) $ 53
Unusual, infrequent and other items:
Non-cash derivative losses (gains), excluding noncontrolling interest 7
(75 )
Early retirement, severance and other costs 2
3
Net gains on early extinguishment of debt —
(4 )
Gains on asset divestitures —
(21 )
Other, net 1
1
Total unusual, infrequent and other items 10
(96 )
Adjusted net income (loss) $ 8
$ (43 )

Net (loss) income attributable to common stock per diluted share $ (0.05 ) $ 1.22
Adjusted net income (loss) per diluted share $ 0.18
$ (1.02 )

~~The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted~~ EBITDAX:

Three months ended
March 31,
2018 2017
(in millions)
Net income $ 9
$ 52
Interest and debt expense, net 92
84
Depreciation, depletion and amortization 119
140
Exploration expense 8
6
Unusual, infrequent and other items 10
(96 )
Other non-cash items 12
14
Adjusted EBITDAX $ 250
$ 200

~~The following table presents the components of our net derivative (losses) gains:~~

Three months ended
March 31,
2018 2017
(in millions)
Non-cash derivative (losses) gains, excluding noncontrolling interest $ (7 ) $ 75
Non-cash derivative losses for noncontrolling interest —
(1 )
Net payments on settled derivatives (31 ) (1 )
Net derivative (losses) gains $ (38 ) $ 73

~~Three months ended March 31, 2018 vs. 2017~~

Oil and gas sales increased 18%, or $88 million, for the three months ended March 31, 2018, compared to the same period of 2017, due to increases of approximately $130 million and $13 million from higher oil and NGL realized prices, respectively, partially offset by $1 million from lower natural gas realized prices and the effects of lower oil and NGL production of $53 million and $1 million, respectively. The higher realized oil prices reflected the significant increase in global oil prices and improved differentials. Our total daily production volumes averaged 123 MBoe in the first quarter of 2018, compared with 132 MBoe in the first quarter of 2017, representing a year-over-year decline rate of 7%. The 2018 production was negatively impacted by 3 MBoe per day due to the PSCs governing our Long Beach operations. Excluding this PSC effect, our year-over-year production decline would have been under 5%. Average oil production decreased by 10%, or 9,000 barrels per day, to 77,000 barrels per day in the three months ended March 31, 2018. NGL production was 16,000 barrels per day for each of the three months ended March 31, 2018 and 2017. Natural gas production increased by 1% to 182 MMcf per day.

Net derivative losses were $38 million for the three months ended March 31, 2018, compared to gains of $73 million in the comparable period of 2017, representing an overall change of $111 million. We recorded non-cash derivative losses of $7 million for the first quarter of 2018, compared to gains of $74 million in the prior comparative period, and made cash payments of $31 million and $1 million for the three months ended March 31, 2018 and 2017, respectively. The non-cash change reflected changes in the commodity price curves based on our derivative positions at the end of each of the respective periods.

The increase in other revenue of $42 million for the three months ended March 31, 2018, compared to the same period of 2017, was largely the result of $35 million from the adoption of new accounting rules on the recognition of revenue in the three months ended March 31, 2018 while the prior comparative period was not adjusted. The increase resulting from the accounting change was offset in its entirety by an increase in other expenses, net with no effect on net income.

Production costs were comparable for the three months ended March 31, 2018 and the same period of the prior year on an absolute dollar basis. Production costs per Boe increased 8% to $19.08 per Boe for the three months ended March 31, 2018, compared to $17.70 per Boe for the same period of 2017, due to lower production volumes between comparative periods.

Our general and administrative expenses were comparable for the three months ended March 31, 2018 and the same period of 2017. The non-cash portion of general and administrative expenses, primarily comprising equity compensation costs, was approximately $4 million and $5 million for the three months ended March 31, 2018 and 2017, respectively.

DD&A expense decreased by $21 million for the three months ended March 31, 2018, compared to the same period of 2017, due to lower DD&A rates and lower volumes resulting in decreases of $14 million and $7 million, respectively.

~~Taxes other than on income increased 15% for the three months ended March 31, 2018, compared to the same period of 2017, largely due to higher greenhouse gas allowance costs.~~

The increase in other expenses of $39 million to $61 million for the three months ended March 31, 2018, compared to $22 million in the same period of 2017, was largely the result of impacts from the adoption of new accounting rules on the recognition of revenue and recording of expenses on the statement of operations. Transportation and processing fees that were previously netted against oil and gas sales were reclassified to other expenses in accordance with these new rules.

Interest and debt expense, net, increased to $92 million for the three months ended March 31, 2018, compared to $84 million in the same period of 2017, primarily due to higher blended interest rates resulting from our 2017 Credit Agreement entered into in the fourth quarter of 2017.

~~Net gains on early extinguishment of debt consisted of the gains on open-market repurchases for the three months ended March 31, 2017.~~

~~Gains on asset divestitures reflected non-core asset sales during the three months ended March 31, 2017.~~

~~Other non-operating expenses for the three months ended March 31, 2018 reflected transaction costs related to our JVs as well as net periodic benefit costs.~~

~~Liquidity and Capital Resources~~

~~Cash Flow Analysis~~

Three months ended
March 31,
2018 2017
(in millions)
Net cash provided by operating activities $ 200
$ 133
Net cash used in investing activities $ (138 ) $ —
Net cash provided (used) by financing activities $ 412
$ (95 )
Adjusted EBITDAX $ 250
$ 200

Our net cash provided by operating activities is sensitive to many variables, including market changes in commodity prices. Commodity price sensitivity also leads to changes in other variables in our business including our level of workover activity and adjustments to our capital program. Our operating cash flow increased 50%, or $67 million, to $200 million for the three months ended March 31, 2018 from $133 million in the same period of 2017 due to higher realized prices, including the effect of hedges, on lower volumes.

Cash interest increased by $17 million for the three months ended March 31, 2018 due to higher blended interest rates and the timing of interest payments. Taxes other than on income increased $5 million from the first quarter of 2017 due to price increases for greenhouse gas allowances. Changes in working capital for the period also contributed to the increase in operating cash flow.

Our net cash used in investing activities of $138 million for the three months ended March 31, 2018 included approximately $134 million of capital investments (net of $5 million in capital-related accruals) and approximately $3 million of acquisition-related prepayments on the office building purchased in April 2018. Our net cash used in investing activities of zero for the three months ended March 31, 2017 included $33 million of capital investments (net of $17 million in capital-related accruals), offset by $33 million in proceeds from asset divestitures.

Our net cash provided by financing activities of $412 million for the three months ended March 31, 2018 primarily comprised of $747 million in net contributions related to our Ares JV and $50 million from the issuance of common stock, partially offset by $363 million 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. For the three months ended March 31, 2017, our net cash used by financing activities of $95 million included approximately $78 million of net payments on our 2014 Revolving Credit Facility, $41 million of payments on the 2014 Term Loan and $26 million of debt repurchases and transaction costs, partially offset by net contributions related to our BSP JV of $49 million.



	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~~adjusted EBITDAX:


	Three months ended March 31,					Three months ended March 31,
	2018			2017		2019		2018
	(in millions)					(in millions)
Net cash provided by operating activities	$	200		$	133	$	158	$	200
Cash interest	61			44		72		61
Exploration expenditures	6			5		4		6
Other changes in operating assets and liabilities	(18		)	17
Working capital changes						67		(18		)
Other, net	1			1		—		1
Adjusted EBITDAX	$	250		$	200	$	301	$	250

~~The increase~~

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 ~~Adjusted EBITDAX~~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, ~~2018, compared to~~2019 from $200 million in the same period of ~~2017,~~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 ~~resulted~~resulting from higher volumes partially offset by lower realized ~~prices after hedge settlements.~~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 ~~JV funding~~JVs to supplement our capital ~~program. In February 2018, we entered into the Ares JV where we received $747 million in net proceeds~~program, fund acquisitions and raised $50 million in a private placement of our common stock with an Ares-led investor group. The net proceeds from the Ares JV were used to pay off the then outstanding balance on our 2014 Revolving Credit Facility of $297 million. During 2017, we closed two key JV transactions. Under these arrangements our JV partners invested $154 million in our drilling programs, some of which is not included in our consolidated results. In April 2018, we acquired the remaining working, surface and mineral interests in our Elk Hills Unit for $460 million in cash and 2.85 million shares of CRC common stock. After the transaction, we expect to add operating cash flow of approximately $100 million per year, at a flat $65 Brent. We also expect to achieve annualized operational savings of $5 million in the short term and approximately $15 million of additional synergies within the following 18 months.other corporate purposes. We expect that the combination of these sources of ~~capital~~funds will be adequate ~~to fund~~for our ~~future~~2019 capital ~~expenditures,~~program, debt service and operating needs.

Significant changes in oil and natural gas prices have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow but lower natural gas prices have a positive indirect effect on operating expenses. The inverse is also true during periods of rising commodity prices. To mitigate some of the risk inherent in oil prices, we have utilized various derivative instruments to hedge price risk. If commodity prices were to prevail throughout 2018 at about current levels, we would expect to be able to fund our 2018 operations and capital program with our operating cash flows. We maintain flexibility within our capital program that helps us to scale our internally funded capital as necessary to stay within our operating cash flow.

~~Given our net operating loss carryforwards from prior periods, we do not expect to pay cash taxes for the foreseeable future.~~

As of March 31, 2018, we have approximately $846 million of available borrowing capacity under our 2014 Revolving Credit Facility, before taking into account a monthly minimum $150 million liquidity requirement. Following the Elk Hills transaction and the debt repurchases completed during April 2018, our available borrowing capacity, on a pro forma basis, would be approximately $800 million. Our ability to borrow funds under our 2014 Revolving Credit Facility is limited by the terms and conditions of that facility and our ability to comply with its covenants. At March 31, 2018, we were in compliance with our debt covenants.

~~As of March 31, 2018,~~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

Outstanding Principal

(in millions)

Interest Rate

Maturity

Security

Credit Agreements

2014 Revolving Credit Facility

—

LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00%

June 30, 2021

Shared First-Priority Lien

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

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

1,000

LIBOR plus 10.375%
ABR plus 9.375%

December 31, 2021

First-Priority Lien

Second Lien Notes

2,248

December 15, 2022^(b)

Second-Priority Lien

2,049

December 15, 2022^(b)

Second-Priority Lien

Senior Notes

5% Senior Notes due 2020

100

January 15, 2020

Unsecured

100

January 15, 2020

Unsecured

5½% Senior Notes due 2021

100

5.5%

September 15, 2021

Unsecured

100

5.5%

September 15, 2021

Unsecured

6% Senior Notes due 2024

193

November 15, 2024

Unsecured

144

November 15, 2024

Unsecured

Total

4,941

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)	~~Under the terms~~The Second Lien Notes require principal repayments of ~~the indenture,~~ approximately ~~$340~~$324 million ~~needs to be repaid by~~in June 2021, ~~and another $70~~$65 million ~~each by~~in December 2021, $67 million in June 2022 and ~~June~~$1,593 million in December 2022.

~~Credit Agreements~~

~~For a detailed description of our credit agreements, second lien notes and senior notes, please see our most recent Form 10-K.~~

2014 Revolving Credit Facility

As of March 31, ~~2018,~~2019, we had approximately ~~$846~~$256 million of available borrowing capacity, before ~~taking into account~~ a $150 million month-end minimum liquidity requirement. ~~The~~Effective May 1, 2019, the borrowing base under this facility was reaffirmed at $2.3 ~~billion in May 2018.~~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, ~~2018~~2019 and December 31, ~~2017,~~2018, we had letters of credit outstanding of approximately ~~$154~~$168 million and ~~$148~~$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 ~~2018,~~2019, we repurchased $2$18 million in ~~aggregate~~ principal amount of our 8% senior secured ~~second-lien~~second lien notes due December 15, 2022 (Second Lien Notes) for ~~$1.6~~$14 million in cash resulting in a ~~$0.4 million pre-tax gain. During April 2018, we also repurchased $95 million in aggregate principal amount of our Second Lien Notes for $79 million in cash, resulting in a $15 million~~ pre-tax gain ~~net~~ of ~~a $1~~$6 million, ~~write-off~~including the effect of unamortized deferred gain and issuance costs.

Other

At March 31, ~~2018,~~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, ~~2018~~2019 would result in a $3$4 million change in annual interest ~~expense.~~expense before the impact of hedges.

~~Hedging~~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, ~~also~~ includes our hedging program. We currently have the following Brent-based crude oil contracts, ~~which include activity subsequent to March 31, 2018:~~as of May 2, 2019:


	Q2 2018		Q3 2018		Q4 2018		Q1 2019		Q2 2019		Q3 2019		Q4 2019		FY 2020		Q2 2019		Q3 2019		Q4 2019		Q1 2020		Q2 2020
Sold Calls:
Barrels per day	6,168		6,127		16,086		16,057		6,023		991		961		503
Weighted-average price per barrel	$	60.24	$	60.24	$	58.91	$	65.75	$	67.01	$	60.00	$	60.00	$	60.00

Purchased Calls:
Barrels per day	—		—		—		2,000		—		—		—		—		5,000		—		—		—		—
Weighted-average price per barrel	$	—	$	—	$	—	$	71.00	$	—	$	—	$	—	$	—	$	68.45	$	—	$	—	$	—	$	—

Purchased Puts:
Barrels per day	1,168		6,127		1,086		29,057		21,023		10,991		961		503		40,000		40,000		35,000		20,000		10,000
Weighted-average price per barrel	$	45.83	$	61.47	$	45.85	$	60.86	$	62.40	$	63.27	$	45.85	$	43.91	$	69.75	$	73.13	$	75.71	$	72.50	$	70.00

Sold Puts:
Barrels per day	29,000		24,000		19,000		30,000		15,000		10,000		—		—		35,000		40,000		35,000		20,000		10,000
Weighted-average price per barrel	$	45.00	$	46.04	$	45.00	$	49.17	$	50.00	$	50.00	$	—	$	—	$	55.71	$	57.50	$	60.00	$	57.50	$	55.00

Swaps:
Barrels per day	44,350		19,000⁽¹⁾		19,000⁽¹⁾		7,000⁽²⁾		—		—		—		—		—		—		—		5,000^(a)		5,000^(b)
Weighted-average price per barrel	$	60.00	$	60.13	$	60.13	$	67.71	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	70.29	$	70.05


~~(1)~~(a)	~~Certain of our counterparties have options to increase swap volumes by up to 29,000 barrels per day at a weighted-average Brent price of $60.50 for~~A counterparty has the ~~second half of 2018.~~


~~(2)~~	~~Certain of our counterparties have options~~option to increase swap volumes by up to 5,000 barrels per day at a weighted-average Brent price of ~~$70.00~~$70.29 for the first quarter of ~~2019.~~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.

~~As of March 31, 2018, a small portion of the~~The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the ~~table~~ above ~~were entered into by our~~table. The BSP ~~joint venture entity, including all of the 2020 hedges. This joint venture~~JV also entered into natural gas swaps for insignificant volumes for periods through ~~July 2020.~~

~~Excluding derivatives~~May 2021. The hedges entered into by ~~our~~the BSP ~~joint venture entity, our hedge program currently covers a significant portion~~JV could affect the timing of ~~our oil production for full year 2018. In~~ the ~~first and second quarters~~redemption of 2019, we hedged approximately 35,000 and 20,000 barrels per day, respectively. The hedges generally form an effective floor around $63 Brent so long as Brent trades above $50 per barrel. A portion of these hedge volumes continues to provide us with upside at prices above $67. For the third quarter of 2019, we have hedged 10,000 barrels of oil per day, providing an effective oil price floor at $65 Brent so long as Brent trades above $50 per barrel. At prices above $65, we continue to benefit from upside. Our philosophy regarding hedging continues to target up to 50% of our production in order to provide more certainty in cash flows and underpin our capital program.JV interest.

Interest-Rate Contracts

In May 2018, we entered into ~~derivatives~~derivative contracts that ~~cap~~limit our interest rate exposure with respect to $1.3 billion of ~~variable rate~~our variable-rate indebtedness. The interest rate ~~caps~~contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the ~~one month~~one-month LIBOR exceeds 2.75% for any monthly period prior to May 4, 2021.

~~2018~~2019 Capital Program

~~With stronger expected cash flows from commodity price improvements and the recent Elk Hills transaction, along~~We entered 2019 with ~~expected synergies, we increased our planned 2018~~an internally funded capital program of $300 to ~~a range from $550 million to $600~~$385 million, which ~~includes approximately $100 to $150~~may be adjusted during the course of the year depending on commodity prices. We obtained an additional $50 million ~~of capital to be funded by~~from our BSP JV ~~partners. The additional capital projects will commence~~partner in the ~~second~~first quarter of ~~2018 with the majority~~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 ~~the investments occurring in the second half of the year.~~

approximately $500 million.

We are focusing our ~~2018~~2019 capital on oil projects. Our capital program will be largely directed to short payout projects, ~~which provide higher margins~~such as primary drilling and ~~low decline rates~~capital workovers, and low-risk projects including waterflood and steamflood investments that ~~we believe~~maintain base production. We will generate cash flow to fund increasing capital budgets that will grow production. Our approach to our 2018 drilling program is consistent with our stated strategy to remain financially disciplined and fund projects through either internally generated cash flow or JV capital to maintain our liquidity and further strengthen our balance sheet. We continue to deploy our partners' capital as part of our BSP and MIRA joint ventures and opportunistically pursue additional strategic relationships. We will deploy capital to projects that help continue to stabilize our production, develop our long-term resources and return our production to a growth profile. Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations that are economically viable in a variety of operating and commodity price conditions and includesfocus on our core fields: Elk Hills and surrounding areas, Wilmington, Kern Front ~~Huntington Beach~~ and the ~~continued~~ delineation and appraisal of ~~our assets which offer future value driven growth such as the Buena Vista, Ventura and southern San Joaquin areas.~~other long-term prospects.

~~Our 2018~~We plan to use 60% of our capital program on drilling ~~program includes~~and development of conventional and unconventional resources. The depth of our ~~primary~~ conventional wells is expected to range from 2,000 to 15,000 feet. ~~With a significant reduction in our drilling costs since 2014, many of our deep~~Our conventional ~~and unconventional~~program includes approximately 140 wells ~~have become more competitive. We expect to use 60% of our capital on drilling projects, which includes 18% of JV funded capital. We are focusing our conventional program~~ primarily in Wilmington, Huntington Beach, Kern Front ~~Pleito Ranch, Yowlumne~~ 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.~~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 ~~16%~~approximately 15% of our ~~2018~~2019 capital program for capital workovers on existing well bores. Capital workovers are some of the highest Value Creation Index ~~(VCI)~~ 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 ~~21%~~15% of our ~~2018~~2019 capital program is intended for facilities development ~~facilities~~ for our newer projects, including pipeline and gathering line interconnections, gas compression and water management systems, and ~~associated~~for mechanical integrity, safety and environmental ~~controls, and about 3%~~projects. About 10% is intended to be used ~~to maintain the mechanical integrity, safety~~for exploration and ~~environmental performance of existing systems and for exploration.~~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, ~~Contingencies~~Commitments and ~~Commitments~~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, ~~2018~~2019 and December 31, ~~2017~~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 ~~on our balance sheet~~ would not be material to our consolidated financial position or results of operations.

Significant Accounting and Disclosure Changes

See Note 2 Accounting and Disclosure Changes ~~under~~in the Notes to the Condensed Consolidated Financial Statements included in Part I ~~Item 1~~ of this ~~report~~Form 10-Q for a discussion of new accounting matters.

~~Safe Harbor Statement Regarding Outlook and~~ Forward-Looking ~~Information~~Statements

The information ~~in this document includes~~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 ~~specifically~~ include those regarding our expectations as to our ~~future~~ future:

financial position, liquidity, cash flows and results of operations

business prospects

transactions and ~~business prospects,~~ 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 ~~drilling~~ and ~~workover program,~~ maintenance capital requirements ~~production, costs, operations,~~

reserves ~~hedging activities, transactions~~

type curves

expected synergies from acquisitions and ~~capital investments and other guidance.~~ joint ventures

Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. ~~You can typically identify forward-looking statements by words such as aim, anticipate,~~While we believe budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying ~~such forward-looking statement, we caution that, while we believe such assumptions or bases to be~~our expectations are reasonable and make them in good faith, ~~assumed facts or bases~~they almost always vary from actual results, sometimes materially. ~~Material risks that may affect our results of operations~~We also believe third-party statements we cite are accurate but have not independently verified them and ~~financial position appear in Part I, Item 1A,~~ ~~Risk Factors~~ ~~of the 2017 Form 10-K.~~

do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:

commodity price ~~fluctuations; the effect of our~~ changes

debt limitations on our financial ~~flexibility;~~ flexibility

insufficient ~~capital, including as a result of lender restrictions or reductions in our borrowing base, lower-than-expected operating~~ cash flow ~~unavailability of~~to fund planned investments, debt repurchases, distributions to JV partners or changes to our capital ~~markets or~~ plan

inability to ~~attract investors; equipment, service~~enter desirable transactions including acquisitions, asset sales and joint ventures

legislative or labor price inflation or unavailability; inability to replace reserves; inability to timely obtain government permits and approvals; inability to monetize selected assets or enter into favorable joint ventures; restrictions imposed by regulationsregulatory 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; risks~~products

joint ventures and acquisitions and our ability to achieve expected synergies

the recoverability of ~~drilling;~~ resources and

unexpected geologic ~~conditions; tax law changes; changes in business strategy; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions;~~ conditions

incorrect estimates of reserves and related future ~~net~~ cash ~~flows; risks related~~flows and the inability to ~~our disposition, joint venture~~replace reserves

changes in business strategy

PSC effects on production and ~~acquisition activities; the recoverability~~unit production costs

effect of ~~resources; limitations~~stock price on ~~our ability~~costs associated with incentive compensation

insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to ~~enter into efficient~~attract potential investors

effects of hedging ~~transactions; steeper-than-expected production decline rates;~~ 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; the effects of litigation; insufficient insurance against and concentration of exposure in California~~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. Readers are cautioned not to place undue reliance on~~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, which speak~~statements. Any forward-looking statement speaks only as of the date ~~hereof. We~~on which such statement is made, and we undertake no ~~responsibility~~obligation to ~~publicly release the~~correct or update any forward-looking statement, whether as a result of ~~any revision of our forward-looking statements after the date they are made.~~new information, future events or otherwise, except as required by applicable law.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, ~~2018,~~2019, there were no material changes into commodity price risk, interest rate risk or counterparty credit risk from the information ~~required to be~~ 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 ~~2017~~2018 Form 10-K, except as discussed below.

Commodity Price Risk

As a result of ~~March 31, 2018,~~our hedge positions for 2019 production, we ~~had a net derivative liability~~protected our downside price risk on approximately 40,000 barrels of ~~$126 million carried~~oil per day at ~~fair value, as determined from~~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 ~~provided by external sources that are not actively quoted,~~range between $55 and $60 per barrel, at which ~~predominantly mature in 2018.~~ 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.

~~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 March 31, 2018, the substantial majority of the credit exposures related to our business was with investment-grade counterparties. We believe exposure to credit-related losses related to our business at March 31, 2018 was not material and losses associated with credit risk have been insignificant for all years presented.


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, ~~2018.~~2019.

During the first quarter of ~~2018,~~2019, we ~~adopted~~implemented new internal controls to support the adoption of the new accounting standard for ~~revenue recognition, Topic 606, and there~~leases, ASC 842. There were no changes in our internal ~~control~~controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that ~~has~~ materially affected, or isare reasonably likely to materially affect, our internal ~~control~~controls over financial reporting.

PART II OTHER INFORMATION


Item 1.	Legal Proceedings

In November 2017, Chevron initiated a contractual dispute resolution process regarding audit claims alleging that it has been underallocated NGLs by approximately $200 million and overcharged for power by $50 million at the Elk Hills field. After extensive review of these claims, we believed that we had in fact overallocated oil, NGLs and natural gas to Chevron. As part of our acquisition of Chevron’s interest in the Elk Hills Unit in April 2018, the parties released their claims against each other under the Unit Operating Agreement.

For information regarding legal proceedings, see Note 7 Lawsuits, Claims and Contingencies in the Notes to the ~~consolidated financial statements~~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, ~~2017.~~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, ~~2017.~~2018.


Item 5.	Other Disclosures

None.


Item 6.	Exhibits



~~4.1~~3.1	~~Registration Rights Agreement, dated as~~Amended and Restated Certificate of ~~April 9, 2018, by and between~~Incorporation of California Resources Corporation ~~and Chevron U.S.A. Inc.~~ (filed as Exhibit ~~4.01~~3.1 to ~~the Company's~~Registrant’s Current Report on Form 8–K filed ~~on April 9, 2018,~~June 3, 2016 and ~~incorporation~~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 ~~2018~~2019 Nonstatutory Stock Option Award Terms and Conditions.

10.2*	Form of ~~2018~~2019 Restricted Stock Unit Award Terms and Conditions.

10.3*	Form of ~~2018~~2019 Performance Stock Unit Award Terms and Conditions.

~~10.4~~	Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC, dated as of February 7, 2018, by and among Elk Hills Power, LLC, California Resources Elk Hills, LLC and ECR Corporate Holdings L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8–K filed on February 7, 2018, and incorporated herein by reference)

~~10.5~~	Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills Power, LLC and California Resources Elk Hills, LLC (filed as Exhibit 10.2 to the Company’s Current Report on Form 8–K filed on February 7, 2018, and incorporated herein by reference)

~~10.6~~	Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills Power, LLC and California Resources Elk Hills, LLC. (filed as Exhibit 10.3 to the Company’s Current Report on Form 8–K filed on February 7, 2018, and incorporated herein by reference)

~~10.7~~	~~Form of Stock Purchase Agreement, dated as of February 7, 2018 (filed as Exhibit 10.4 to the Company’s Current Report on Form 8–K filed on February 7, 2018, and incorporated herein by reference)~~

~~10.8~~	Registration Rights Agreement, dated as of February 7, 2018, by and between California Resources Corporation and the purchasers named therein (filed as Exhibit 10.5 to the Company’s Current Report on Form 8–K filed on February 7, 2018, and incorporated herein by reference)

12*	~~Computation of Ratios of Earnings to Fixed Charges.~~

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 ~~9, 2018~~2, 2019	/s/ Roy M. Pineci
		Roy M. Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)

4236



	As Reported ASC 606			Previous U.S. GAAP			Change
REVENUES AND OTHER
Oil and gas sales	$	575		$	568		$	7
Net derivative losses	(38		)	(38		)	—
Other revenue	72			37			35
Total revenues and other	609			567			42

COSTS AND OTHER
Production costs	212			212			—
General and administrative expenses	63			63			—
Depreciation, depletion and amortization	119			119			—
Taxes other than on income	38			38			—
Exploration expense	8			8			—
Other expenses, net	61			19			42
Total costs and other	501			459			42
OPERATING (LOSS) INCOME	108			108			—

NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(92		)	(92		)	—
Other non-operating expenses	(7		)	(7		)	—
(LOSS) INCOME BEFORE INCOME TAXES	9			9			—
Income tax benefit	—			—			—
NET (LOSS) INCOME	9			9			—
Net (income) loss attributable to noncontrolling interests	(11		)	(11		)	—
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$	(2	)	$	(2	)	$	—



Condensed Consolidating Balance Sheets
	Parent			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
As of March 31, 2018	(in millions)
Total current assets	$	491		$	414		$	51		$	(7	)	$	949
Total property, plant and equipment, net	23			5,153			538			—			5,714
Investments in consolidated subsidiaries	5,050			95			—			(5,145		)	—
Other assets	—			22			14			—			36
TOTAL ASSETS	$	5,564		$	5,684		$	603		$	(5,152	)	$	6,699

Total current liabilities	125			680			8			(7		)	806
Long-term debt	4,941			—			—			—			4,941
Deferred gain and issuance costs, net	275			—			—			—			275
Other long-term liabilities	153			448			6			—			607
Amounts due to (from) affiliates	833			(833		)	—			—			—
Mezzanine equity	—			—			724			—			724
Total equity	(763		)	5,389			(135		)	(5,145		)	(654		)
TOTAL LIABILITIES AND EQUITY	$	5,564		$	5,684		$	603		$	(5,152	)	$	6,699



As of December 31, 2017
Total current assets	$	13		$	464		$	12	$	(6	)	$	483
Total property, plant and equipment, net	24			5,580			92		—			5,696
Investments in consolidated subsidiaries	5,105			606			—		(5,711		)	—
Other assets	—			27			1		—			28
TOTAL ASSETS	$	5,142		$	6,677		$	105	$	(5,717	)	$	6,207

Total current liabilities	122			613			3		(6		)	732
Long-term debt	5,306			—			—		—			5,306
Deferred gain and issuance costs, net	287			—			—		—			287
Other long-term liabilities	154			445			3		—			602
Amounts due to (from) affiliates	87			(87		)	—		—			—
Total equity	(814		)	5,706			99		(5,711		)	(720		)
TOTAL LIABILITIES AND EQUITY	$	5,142		$	6,677		$	105	$	(5,717	)	$	6,207



For the three months ended March 31, 2017
Net cash (used) provided by operating activities	$	(139	)	$	274		$	(2	)	$	—	$	133
Net cash (used) provided by investing activities	(1		)	1			—			—		—
Net cash provided (used) by financing activities	140			(284		)	49			—		(95		)
(Decrease) increase in cash and cash equivalents	—			(9		)	47			—		38
Cash and cash equivalents—beginning of period	—			12			—			—		12
Cash and cash equivalents— end of period	$	—		$	3		$	47		$	—	$	50