California Resources Corp - Quarter Report: 2018 March (Form 10-Q)

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

¨ 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, Suite 900 Los Angeles, California (Address of principal executive offices)		91311 (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 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, smaller reporting company or an emerging growth company. (See definition of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act):



Large Accelerated Filer	o	Accelerated Filer	þ	Non-Accelerated Filer	o
Smaller Reporting Company	o	Emerging Growth Company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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



Shares of common stock outstanding as of March 31, 2018	45,337,486

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 Condensed Consolidated Financial Statements	7
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	General	22
	Business Environment and Industry Outlook	22
	Seasonality	23
	Joint Ventures	23
	Private Placement	25
	Acquisitions and Divestitures	25
	Operations	26
	Fixed and Variable Costs	26
	Production and Prices	27
	Balance Sheet Analysis	28
	Statement of Operations Analysis	29
	Liquidity and Capital Resources	33
	2018 Capital Program	36
	Lawsuits, Claims, Contingencies and Commitments	37
	Significant Accounting and Disclosure Changes	37
	Safe Harbor Statement Regarding Outlook and Forward-Looking Information	38
Item 3	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4	Controls and Procedures	39

Part II
Item 1	Legal Proceedings	40
Item 1A	Risk Factors	40
Item 5	Other Disclosures	40
Item 6	Exhibits	41

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of March 31, 2018 and December 31, 2017

(in millions, except share data)



	March 31,			December 31,
	2018			2017
CURRENT ASSETS
Cash and cash equivalents	$	494		$	20
Trade receivables	244			277
Inventories	56			56
Other current assets, net	155			130
Total current assets	949			483
PROPERTY, PLANT AND EQUIPMENT	21,397			21,260
Accumulated depreciation, depletion and amortization	(15,683		)	(15,564		)
Total property, plant and equipment, net	5,714			5,696
OTHER ASSETS	36			28
TOTAL ASSETS	$	6,699		$	6,207



CURRENT LIABILITIES
Accounts payable	292			257
Accrued liabilities	514			475
Total current liabilities	806			732
LONG-TERM DEBT	4,941			5,306
DEFERRED GAIN AND ISSUANCE COSTS, NET	275			287
OTHER LONG-TERM LIABILITIES	607			602
MEZZANINE EQUITY
Redeemable noncontrolling interest	724			—
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)	—			—
Additional paid-in capital	4,930			4,879
Accumulated deficit	(5,672		)	(5,670		)
Accumulated other comprehensive loss	(21		)	(23		)
Total equity attributable to common stock	(763		)	(814		)
Noncontrolling interests	109			94
Total equity	(654		)	(720		)
TOTAL LIABILITIES AND EQUITY	$	6,699		$	6,207

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 and 2017

(in millions, except share data)



	Three months ended March 31,
	2018			2017
REVENUES AND OTHER
Oil and gas sales	$	575		$	487
Net derivative (losses) gains	(38		)	73
Other revenue	72			30
Total revenues and other	609			590

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

NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(92		)	(84		)
Net gains on early extinguishment of debt	—			4
Gains on asset divestitures	—			21
Other non-operating expenses	(7		)	(4		)
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

Net (loss) income attributable to common stock per share
Basic	$	(0.05	)	$	1.23
Diluted	$	(0.05	)	$	1.22

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 and 2017

(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


(a)	No associated tax for the three months ended March 31, 2018 and 2017. 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 and 2017

(in millions)



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

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

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from 2014 Revolving Credit Facility	81			221
Repayments of 2014 Revolving Credit Facility	(444		)	(299		)
Payments on 2014 Term Loan	—			(41		)
Debt repurchases	(2		)	(24		)
Debt transaction costs	—			(2		)
Contribution from noncontrolling interest holders, net	747			49
Distributions paid to noncontrolling interest holders	(18		)	—
Issuance of common stock	50			1
Shares canceled for taxes	(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

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 and 2017

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


(a)	Excludes $14 million of consolidated net income attributable to redeemable noncontrolling interest recorded in mezzanine equity.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

March 31, 2018

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 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). We 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,’’ ‘‘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 and December 31, 2017 and the statements of operations, comprehensive income, cash flows and equity for the three months ended March 31, 2018 and 2017. We have eliminated all of our significant intercompany transactions and accounts. We account for our share of oil and gas exploration and production 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 balance sheets, statements of operations 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 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.


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, the FASB issued rules on the recognition of revenue, which created Topic 606 (ASC 606), which we adopted on January 1, 2018 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported 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 did not have an adjustment to opening retained earnings upon adoption. The new revenue standard required certain sales-related costs to be reported as other expense as opposed to being netted against oil and gas sales or other revenue. See Note 11 Revenue Recognition 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 and cash equivalents consists primarily of highly liquid investments with original maturities of three months or less and are stated at cost, which approximates fair value.

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



	March 31, 2018		December 31, 2017
	(in millions)
Amounts due from joint interest partners	$	76	$	76
Derivative assets from commodities contracts	44		23
Prepaid expenses	23		19
Assets held for sale	12		12
Other current assets, net	$	155	$	130

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



	March 31, 2018		December 31, 2017
	(in millions)
Derivative liabilities from commodities contracts	$	170	$	154
Accrued taxes other than on income	143		130
Accrued interest	67		23
Accrued employee-related costs	52		86
Other	82		82
Accrued liabilities	$	514	$	475

Other long-term liabilities included asset retirement obligations of $407 million and $403 million at March 31, 2018 and December 31, 2017, respectively.

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 and 2017. Interest paid, net of capitalized amounts, totaled approximately $60 million and $44 million for the three months ended March 31, 2018 and 2017, respectively.

NOTE 4 INVENTORIES

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



	March 31, 2018		December 31, 2017
	(in millions)
Materials and supplies	$	54	$	53
Finished goods	2		3
Total	$	56	$	56

NOTE 5 DEBT

As of March 31, 2018 and December 31, 2017, our long-term debt consisted of the following credit agreements, second lien notes and senior notes:



	Outstanding Principal (in millions)				Interest Rate	Maturity	Security
	March 31, 2018		December 31, 2017
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
2017 Credit Agreement	1,300		1,300		LIBOR plus 4.75% ABR plus 3.75%	December 31, 2022^(a)	Shared First-Priority Lien
2016 Credit Agreement	1,000		1,000		LIBOR plus 10.375% ABR plus 9.375%	December 31, 2021	First-Priority Lien
Second Lien Notes
Second Lien Notes	2,248		2,250		8%	December 15, 2022^(b)	Second-Priority Lien
Senior Notes
5% Senior Notes due 2020	100		100		5%	January 15, 2020	Unsecured
5½% Senior Notes due 2021	100		100		5.5%	September 15, 2021	Unsecured
6% Senior Notes due 2024	193		193		6%	November 15, 2024	Unsecured
Total	$	4,941	$	5,306


(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 is outstanding at that time.


(b)	Under the terms of the indenture, approximately $340 million needs to be repaid by June 2021 and another $70 million each by December 2021 and June 2022.

Deferred Gain and Issuance Costs

As of March 31, 2018, net deferred gain and issuance costs were $275 million, consisting of $396 million of deferred gains offset by $85 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.

2014 Revolving Credit Facility

In February 2018, we paid $297 million of the then outstanding balance on our $1 billion senior revolving loan 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 borrowing base under this facility was reaffirmed at $2.3 billion in May 2018. 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 and December 31, 2017, we had letters of credit outstanding of approximately $154 million and $148 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

Repurchases

In the first quarter of 2018, we repurchased $2 million in aggregate principal amount of our 8% senior secured second-lien notes due December 15, 2022 (Second Lien Notes) for $1.6 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 million write-off of deferred 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 and December 31, 2017, including the fair value of variable-rate debt, was approximately $4.4 billion and $4.8 billion, respectively, compared to a carrying value of approximately $4.9 billion and $5.3 billion, respectively.

Other

As of March 31, 2018, 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 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

The following table presents the changes in noncontrolling interests by entity, reported in equity attributable to noncontrolling interest and mezzanine equity on the consolidated balance sheets, for the three months ended March 31, 2018 (in millions):



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

Ares Management L.P. (Ares)

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 for transaction costs.

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.

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.

Benefit Street Partners (BSP)

In February 2017, we entered into a joint venture with BSP (BSP JV) where BSP will contribute up to $250 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.

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 and December 31, 2017 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 the future in connection with 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 to the Spin-off and liabilities related to operation of our business while it was still owned by Occidental. As of March 31, 2018, we are not aware of material indemnity claims pending or threatened against the company.

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 adequate liquidity and improving 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.

As of March 31, 2018, we did not have any derivatives designated as hedges. 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. As part of our hedging program, we entered into a number of derivative transactions that resulted in the following Brent-based crude oil contracts as of March 31, 2018:



	Q2 2018		Q3 2018		Q4 2018		Q1 2019		Q2 2019		Q3 2019		Q4 2019		FY 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		—		—		—		—
Weighted-average price per barrel	$	—	$	—	$	—	$	71.00	$	—	$	—	$	—	$	—

Purchased Puts:
Barrels per day	1,168		6,127		1,086		24,057		11,023		991		961		503
Weighted-average price per barrel	$	45.83	$	61.47	$	45.85	$	60.00	$	60.05	$	45.85	$	45.85	$	43.91

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

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 crude oil derivatives in the table above were entered into by 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.

The outcomes of the derivative positions are as follows:


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


•	Purchased 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.

Fair Value of Derivatives

Our commodity derivatives 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. The following table presents the fair values (at gross and net) of our outstanding derivatives as of March 31, 2018 and December 31, 2017 (in millions):



	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, 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	)

NOTE 9 EARNINGS PER SHARE

We compute basic and diluted earnings per share (EPS) using the two-class method required for participating securities. Certain restricted and performance stock awards are considered participating securities when such shares have non-forfeitable dividend rights at the same rate as 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 potentially dilutive securities.

The following table presents the calculation of basic and diluted EPS for the three months ended March 31, 2018 and 2017:



	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

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,
	2018					2017
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	—		$	1	$	—		$	1
Interest cost	1			1		1			1
Expected return on plan assets	(1		)	—		(1		)	—
Settlement loss	2			—		3			—
Total	$	2		$	2	$	3		$	2

During the three months ended March 31, 2018 and 2017, we contributed $1 million and $4 million, respectively, to our defined benefit pension plans. We expect to satisfy minimum funding requirements with contributions of $3 million to our defined benefit pension plans during the remainder of 2018. The 2018 and 2017 settlements were 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 marketing activities related to storage and managing excess pipeline capacity and sales of power.

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 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 are recording these costs as a component of other expenses, net.

Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount which 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 Elk Hills power plant is sold to the grid through wholesale power marketing entities and to a utility under a power purchase and sale agreement, which includes a capacity payment. Revenue is recognized when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. We report electricity sales as other revenue. 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. 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. 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

Marketing revenues represent our activities associated with storing and transporting 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.

To transport our natural gas, 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 report our marketing activities on a gross basis with purchases and costs reported in other expenses, net and sales recorded in other revenue.

Disaggregation of Revenue

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



Oil and gas sales:
Oil	$	466
NGLs	63
Natural gas	46
	575
Other revenue:
Electricity	24
Marketing	47
Interest income	1
	72
Net derivative losses	(38		)
Total revenues and other	$	609

The impact of the adoption of ASC 606 on our condensed consolidated statement of operations 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	)	$	—

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 12 INCOME TAXES

For the three ended March 31, 2018 and 2017, we did not provide any current or deferred tax provision or benefit. The difference between our statutory tax rate and our effective tax rate for the periods is primarily related to an increase in 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 and do not believe any of our valuation allowance as of March 31, 2018 will be released within the next 12 months. 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 on December 22, 2017, included significant changes 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.

NOTE 14 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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 of our subsidiaries do not guarantee our Credit Facilities and Second Lien Notes (Non-Guarantor Subsidiaries) either because they hold assets that are less than 1% of our total consolidated assets or because they are not considered a "subsidiary" under the applicable financing agreement. The following condensed consolidating balance sheets 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 of our parent company, CRC (Parent), our combined Guarantor Subsidiaries, our combined Non-Guarantor Subsidiaries and the elimination entries necessary to arrive at the information for CRC on a consolidated basis.

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



Condensed Consolidating Balance Sheets
	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 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 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. These and other factors make it impossible to predict realized prices reliably.

Much of the global exploration and production industry has been challenged in the low-commodity price cycle in recent years, putting pressure on the industry's ability to generate positive cash flow and access capital. Global oil 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 2018 than the comparable period of 2017 due to higher natural gas production.

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



	Three months ended March 31,
	2018		2017
Brent oil ($/Bbl)	$	67.18	$	54.66
WTI oil ($/Bbl)	$	62.87	$	51.91
NYMEX gas ($/MMBtu)	$	2.87	$	3.26

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% of the oil consumed in 2017 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 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 in California crude oil production.

Prices and differentials for NGLs 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 magnify pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Transportation capacity influences prices because California imports about 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 lower transportation costs. Due to our much lower natural gas production compared to our oil production, the changes in natural gas prices have a smaller impact on our operating results.

In addition to selling natural gas, we also use 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, but higher prices still have a net positive effect on our operating results. Conversely, lower natural gas prices generally have a net negative effect on our results, but lower the cost of our steamflood projects and power generation.

Our earnings are also affected by the performance of our processing and power generation assets. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Additionally, we use part of the electricity from the Elk Hills power plant to reduce operating costs at Elk Hills and nearby fields and increase reliability. The remaining electricity is sold to the grid and a utility under a power purchase and sales agreement that 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 the cyclical nature of commodity prices while maintaining adequate liquidity and improving our ability to comply with our debt covenants in case of price deterioration. 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 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

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 million net mineral acres, approximately 60% of which we hold in fee and approximately 15% of which is held by production. Our oil and gas leases have primary terms ranging from one to ten years, which are extended through the end of production once it commences. We also own a network of strategically placed infrastructure that is integrated with, and complementary to, our operations, including gas plants, oil and gas gathering systems, power plants and other related assets, which we use to 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 contracts represented over 15% of our production for the quarter ended March 31, 2018.

In addition, in line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under the PSCs in our 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. This difference in reporting full operating costs but only our net share of production inflates our operating costs per barrel, with an equal corresponding increase in revenues, with 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 initiatives include exploring opportunities to use our land for renewable energy opportunities such as solar energy projects; agricultural activities such as the production of fruits and nuts; and commercial real estate. We are also exploring carbon dioxide capture and storage projects and reclaimed water opportunities.

Fixed and Variable Costs

Our total production costs consist of variable costs that tend to vary depending on 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 certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program, 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 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 and 2017:



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

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


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 per day.


(a)	Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

The following table sets forth the average realized prices for our products for the three months ended March 31, 2018 and 2017:



	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


(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 to March 31, 2018 are discussed below:



	March 31, 2018			December 31, 2017
	(in millions)
Cash and cash equivalents	$	494		$	20
Trade receivables	$	244		$	277
Inventories	$	56		$	56
Other current assets, net	$	155		$	130
Property, plant and equipment, net	$	5,714		$	5,696
Other assets	$	36		$	28
Accounts payable	$	292		$	257
Accrued liabilities	$	514		$	475
Long-term debt	$	4,941		$	5,306
Deferred gain and issuance costs, net	$	275		$	287
Other long-term liabilities	$	607		$	602
Mezzanine equity	$	724		$	—
Equity attributable to common stock	$	(763	)	$	(814	)
Equity attributable to noncontrolling interests	$	109		$	94

Cash and cash equivalents at March 31, 2018 included the remaining proceeds from the issuance of the preferred and common member interests in the Ares JV, after the pay off of $297 million on the then outstanding balance of our 2014 Revolving Credit Facility. See Liquidity and Capital Resources for additional discussion of changes in cash and cash equivalents.

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 derivative assets. The increase in property, plant and equipment reflected capital investments for the period, partially offset by depreciation, depletion and amortization (DD&A).

The increase in accounts payable for the quarter ended March 31, 2018 was primarily due to the timing of payments and the gradual ramp up 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 the timing of payments. These increases were partially offset by a decrease in accrued employee-related costs, which reflected employee bonus payments in the first quarter of 2018. The decrease in long-term debt primarily reflected the pay off 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 the amortization of deferred gains, partially offset by the amortization of deferred issuance costs.

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 reflected the issuance of common stock in a private placement. Equity attributable to noncontrolling interest primarily reflected the contribution from Ares, partially offset by distributions to Ares and BSP.

Statement 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,
	2018		2017
Production costs	$	19.08	$	17.70
Production costs, excluding effects of PSC contracts^(a)	$	17.47	$	16.66
Field general and administrative expenses^(b)	$	0.72	$	0.76
Field depreciation, depletion and amortization^(b)	$	9.63	$	11.07
Field taxes other than on income^(b)	$	2.70	$	2.27


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


(b)	Excludes corporate amounts.

Consolidated Results of Operations

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



	Three months ended March 31,
	2018			2017
	(in millions)
Oil and gas sales^(a)	$	575		$	487
Net derivative (losses) gains	(38		)	73
Other revenue^(a)	72			30
Production costs	(212		)	(211		)
General and administrative expenses^(b)	(63		)	(63		)
Depreciation, depletion and amortization	(119		)	(140		)
Taxes other than on income	(38		)	(33		)
Exploration expense	(8		)	(6		)
Other expenses, net^(a)	(61		)	(22		)
Interest and debt expense, net	(92		)	(84		)
Net gains on early extinguishment of debt	—			4
Gains on asset divestitures	—			21
Other non-operating expenses	(7		)	(4		)
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

Adjusted net income (loss)	$	8		$	(43	)
Adjusted EBITDAX	$	250		$	200
Effective tax rate	—		%	—		%

(a)

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


(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 gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) which excludes those items. This measure is not meant to disassociate 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).

We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items; and other non-cash items. We believe Adjusted EBITDAX 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 is a non-GAAP measure, the amounts included in the calculation of Adjusted EBITDAX were computed in accordance with GAAP. A version of this measure 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.

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



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

The increase in Adjusted EBITDAX for the three months ended March 31, 2018, compared to the same period of 2017, primarily resulted from higher realized prices after hedge settlements.

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 to supplement our capital program. In February 2018, we entered into the Ares JV where we received $747 million in net proceeds 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. We expect the combination of these sources of capital will be adequate to fund our future capital expenditures, 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, our long-term debt consisted of the following credit agreements, second lien notes and senior notes:



	Outstanding Principal (in millions)		Interest Rate	Maturity	Security
Credit Agreements
2014 Revolving Credit Facility	$	—	LIBOR plus 3.25%-4.00% ABR plus 2.25%-3.00%	June 30, 2021	Shared First-Priority Lien
2017 Credit Agreement	1,300		LIBOR plus 4.75% ABR plus 3.75%	December 31, 2022^(a)	Shared First-Priority Lien
2016 Credit Agreement	1,000		LIBOR plus 10.375% ABR plus 9.375%	December 31, 2021	First-Priority Lien
Second Lien Notes
Second Lien Notes	2,248		8%	December 15, 2022^(b)	Second-Priority Lien
Senior Notes
5% Senior Notes due 2020	100		5%	January 15, 2020	Unsecured
5½% Senior Notes due 2021	100		5.5%	September 15, 2021	Unsecured
6% Senior Notes due 2024	193		6%	November 15, 2024	Unsecured
Total	$	4,941


(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 is outstanding at that time.


(b)	Under the terms of the indenture, approximately $340 million needs to be repaid by June 2021 and another $70 million each by December 2021 and June 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, we had approximately $846 million of available borrowing capacity, before taking into account a $150 million month-end minimum liquidity requirement. The borrowing base under this facility was reaffirmed at $2.3 billion in May 2018. 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 and December 31, 2017, we had letters of credit outstanding of approximately $154 million and $148 million, respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

Repurchases

In the first quarter of 2018, we repurchased $2 million in aggregate principal amount of our 8% senior secured second-lien notes due December 15, 2022 (Second Lien Notes) for $1.6 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 million write-off of deferred issuance costs.

Other

At March 31, 2018, 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 would result in a $3 million change in annual interest expense.

Hedging

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:



	Q2 2018		Q3 2018		Q4 2018		Q1 2019		Q2 2019		Q3 2019		Q4 2019		FY 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		—		—		—		—
Weighted-average price per barrel	$	—	$	—	$	—	$	71.00	$	—	$	—	$	—	$	—

Purchased Puts:
Barrels per day	1,168		6,127		1,086		29,057		21,023		10,991		961		503
Weighted-average price per barrel	$	45.83	$	61.47	$	45.85	$	60.86	$	62.40	$	63.27	$	45.85	$	43.91

Sold Puts:
Barrels per day	29,000		24,000		19,000		30,000		15,000		10,000		—		—
Weighted-average price per barrel	$	45.00	$	46.04	$	45.00	$	49.17	$	50.00	$	50.00	$	—	$	—

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	$	—	$	—	$	—	$	—


(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 crude oil derivatives in the table above were entered into by our BSP joint venture entity, including all of the 2020 hedges. This joint venture also entered into natural gas swaps for insignificant volumes for periods through July 2020.

Excluding derivatives entered into by our BSP joint venture entity, our hedge program currently covers a significant portion of our oil production for full year 2018. In the first and second quarters 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.

In May 2018 we entered into derivatives that cap our interest rate exposure with respect to $1.3 billion of variable rate indebtedness. The interest rate caps 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.

2018 Capital Program

With stronger expected cash flows from commodity price improvements and the recent Elk Hills transaction, along with expected synergies, we increased our planned 2018 capital program to a range from $550 million to $600 million, which includes approximately $100 to $150 million of capital to be funded by our JV partners. The additional capital projects will commence in the second quarter of 2018 with the majority of the investments occurring in the second half of the year.

We are focusing our 2018 capital on oil projects, which provide higher margins and low decline rates that we believe 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 includes our core fields: Elk Hills, 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.

Our 2018 drilling program includes 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 conventional and unconventional 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 primary drilling. We intend to drill unconventional wells in Buena Vista.

We also plan to use 16% of our 2018 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% of our 2018 capital program is intended for development facilities for our newer projects, including pipeline and gathering line interconnections, gas compression, water management systems and associated safety and environmental controls, and about 3% is intended to be used to maintain the mechanical integrity, safety and environmental performance of existing systems and for exploration.

Lawsuits, Claims, Contingencies and Commitments

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

Significant Accounting and Disclosure Changes

See Note 2 Accounting and Disclosure Changes under Part I Item 1 of this report for a discussion of new accounting matters.

Safe Harbor Statement Regarding Outlook and Forward-Looking Information

The information in this document includes 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 our expectations as to our future financial position, liquidity, cash flows, results of operations and business prospects, budgets, drilling and workover program, maintenance capital requirements, production, costs, operations, reserves, hedging activities, transactions and capital investments and other guidance. 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, 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 reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect our results of operations and financial position appear in Part I, Item 1A, Risk Factors of the 2017 Form 10-K.

Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the effect of our debt on our financial flexibility; insufficient capital, including as a result of lender restrictions or reductions in our borrowing base, lower-than-expected operating cash flow, unavailability of capital markets or inability to attract investors; equipment, service 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 regulations 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 of drilling; 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; incorrect estimates of reserves and related future net cash flows; risks related to our disposition, joint venture and acquisition activities; the recoverability of resources; limitations on our ability to enter into efficient hedging transactions; steeper-than-expected production decline rates; lower-than-expected production, reserves or resources from development projects or acquisitions; the effects of litigation; insufficient insurance against and concentration of exposure in California to accidents, mechanical failures, transportation or storage constraints, labor difficulties, cyber attacks or other catastrophic events. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

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, there were no material changes in 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 Form 10-K, except as discussed below.

Commodity Price Risk

As of March 31, 2018, we had a net derivative liability of $126 million carried at fair value, as determined from prices provided by external sources that are not actively quoted, which predominantly mature in 2018. 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.

During the first quarter of 2018, we adopted the new accounting standard for revenue recognition, Topic 606, and there were no changes in our internal control 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 is reasonably likely to materially affect, our internal control 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 to the consolidated financial statements 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.


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.


Item 5.	Other Disclosures

None.


Item 6.	Exhibits



4.1	Registration Rights Agreement, dated as of April 9, 2018, by and between California Resources Corporation and Chevron U.S.A. Inc. (filed as Exhibit 4.01 to the Company's Current Report on Form 8–K filed on April 9, 2018, and incorporation herein by reference)

10.1*	Form of 2018 Nonstatutory Stock Option Award Terms and Conditions.

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

10.3*	Form of 2018 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	/s/ Roy Pineci
		Roy Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)