California Resources (CRC) 10-Q 9 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2018shares
Document and Entity Information
Entity Registrant Name	California Resources Corp
Entity Central Index Key	1,609,253
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding	45,337,486
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 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

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Condensed Consolidated Balance Sheets
Preferred stock, authorized shares	20,000,000	20,000,000
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, outstanding shares	0	0
Common stock, authorized shares	200,000,000	200,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, outstanding shares	45,337,486	42,901,946

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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
NET (LOSS) 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 (in dollars per share)	$ (0.05)	$ 1.23
Diluted (in dollars per share)	$ (0.05)	$ 1.22

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Condensed Consolidated Statements of Comprehensive Income
Net income		$ 9	$ 52
Other comprehensive income items:
Reclassification to income of realized losses on pension and postretirement	[1]	2	3
Total other comprehensive income, net of tax		2	3
Comprehensive (income) loss attributable to noncontrolling interest		$ (11)	1
Comprehensive income attributable to common stock			$ 56
[1]	No associated tax for the three months ended March 31, 2018 and 2017. See Note 10 Pension and Postretirement Benefit Plans, for additional information.

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Condensed Consolidated Statements of Comprehensive Income
Pension and postretirement income, associated tax	$ 0	$ 0

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Equity - USD ($) $ in Millions		Equity Attributable to Common Stock	Additional Paid-in Capital	Accumulated Deficit	Accumulated Other Comprehensive (Loss) Income	Noncontrolling Interest	Total
Balance at Dec. 31, 2016		$ (557)	$ 4,861	$ (5,404)	$ (14)		$ (557)
Increase (decrease) in Equity
Net income (loss)		53		53		$ (1)	52
Contributions from noncontrolling interest holders, net						49	49
Other comprehensive income		3			3		3
Share-based compensation, net		6	6				6
Balance at Mar. 31, 2017		(495)	4,867	(5,351)	(11)	48	(447)
Balance at Dec. 31, 2017		(814)	4,879	(5,670)	(23)	94	(720)
Increase (decrease) in Equity
Net income (loss)	[1]	(2)		(2)		(3)	(5)
Contributions 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 at Mar. 31, 2018		$ (763)	$ 4,930	$ (5,672)	$ (21)	$ 109	$ (654)
[1]	Excludes $14 million of consolidated net income attributable to redeemable noncontrolling interest recorded in mezzanine equity.

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Equity (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Condensed Consolidated Statements of Equity
Net income attributable to redeemable noncontrolling interest	$ 14

THE SPIN-OFF AND BASIS OF PRESE

THE SPIN-OFF AND BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2018
THE SPIN-OFF AND BASIS OF PRESENTATION
THE SPIN-OFF AND BASIS OF PRESENTATION	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.

ACCOUNTING AND DISCLOSURE CHANG

ACCOUNTING AND DISCLOSURE CHANGES	3 Months Ended
	Mar. 31, 2018
ACCOUNTING AND DISCLOSURE CHANGES
ACCOUNTING AND DISCLOSURE CHANGES	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.

OTHER INFORMATION

OTHER INFORMATION	3 Months Ended
	Mar. 31, 2018
OTHER INFORMATION
OTHER INFORMATION	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, December 31, 2018 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, December 31, 2018 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.

INVENTORIES

INVENTORIES	3 Months Ended
	Mar. 31, 2018
INVENTORIES
INVENTORIES	NOTE 4 INVENTORIES Inventories as of March 31, 2018 and December 31, 2017 consisted of the following: March 31, December 31, 2018 2017 (in millions) Materials and supplies $ 54 $ 53 Finished goods 2 3 Total $ 56 $ 56

DEBT

DEBT	3 Months Ended
	Mar. 31, 2018
DEBT
DEBT	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, December 31, 2018 2017 Credit Agreements 2014 Revolving Credit Facility $ — $ 363 LIBOR plus 3.25%-4.00% June 30, 2021 Shared First-Priority Lien 2017 Credit Agreement 1,300 1,300 LIBOR plus 4.75% December 31, 2022 (a) Shared First-Priority Lien 2016 Credit Agreement 1,000 1,000 LIBOR plus 10.375% 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 5 1/2 % 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.

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	3 Months Ended
	Mar. 31, 2018
NONCONTROLLING INTERESTS
NONCONTROLLING INTERESTS	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): Mezzanine Equity Equity – Noncontrolling Noncontrolling Interest 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.

LAWSUITS, CLAIMS, COMMITMENTS A

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2018
LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES
LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES	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.

DERIVATIVES

DERIVATIVES	3 Months Ended
	Mar. 31, 2018
DERIVATIVES
DERIVATIVES	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 Q3 Q4 Q1 Q2 Q3 Q4 FY 2018 2018 2018 2019 2019 2019 2019 2020 Sold Calls: Barrels per day 6,168 6,127 16,086 16,057 6,023 991 503 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 11,023 991 503 Weighted-average price per barrel $ 45.83 $ 61.47 $ 45.85 $ 60.00 $ 60.05 $ 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 Gross Gross Net Fair Value Amounts Amounts Presented in Balance Sheet Recognized at Offset in the the Balance Classification Fair Value Balance Sheet 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 Gross Gross Net Fair Value Amounts Amounts Presented in Balance Sheet Recognized at Offset in the the Balance Classification Fair Value Balance Sheet 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)

EARNINGS PER SHARE

EARNINGS PER SHARE	3 Months Ended
	Mar. 31, 2018
EARNINGS PER SHARE
EARNINGS PER SHARE	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

PENSION AND POSTRETIREMENT BENE

PENSION AND POSTRETIREMENT BENEFIT PLANS	3 Months Ended
	Mar. 31, 2018
PENSION AND POSTRETIREMENT BENEFIT PLANS
PENSION AND POSTRETIREMENT BENEFIT PLANS	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 Postretirement Pension Postretirement Benefit Benefit Benefit 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.

REVENUE RECOGNITION

REVENUE RECOGNITION	3 Months Ended
	Mar. 31, 2018
REVENUE RECOGNITION
REVENUE RECOGNITION	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 Previous ASC 606 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.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2018
INCOME TAXES
INCOME TAXES	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.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2018
SUBSEQUENT EVENTS
SUBSEQUENT EVENT	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.

CONDENSED CONSOLIDATING FINANCI

CONDENSED CONSOLIDATING FINANCIAL INFORMATION	3 Months Ended
	Mar. 31, 2018
CONDENSED CONSOLIDATING FINANCIAL INFORMATION
CONDENSED CONSOLIDATING FINANCIAL INFORMATION	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 Combined Combined Non- Guarantor Guarantor Parent Subsidiaries 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 Combined Combined Non- Guarantor Guarantor Parent Subsidiaries 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 Combined Combined Non- Guarantor Guarantor Parent Subsidiaries 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

THE SPIN-OFF AND BASIS OF PRE24

THE SPIN-OFF AND BASIS OF PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 2018
THE SPIN-OFF AND BASIS OF PRESENTATION
Basis of Presentation	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.

OTHER INFORMATION (Tables)

OTHER INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2018
OTHER INFORMATION
Schedule of other current assets	March 31, December 31, 2018 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
Schedule of accrued liabilities	March 31, December 31, 2018 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

INVENTORIES (Tables)

INVENTORIES (Tables)	3 Months Ended
	Mar. 31, 2018
INVENTORIES
Schedule of Inventories	March 31, December 31, 2018 2017 (in millions) Materials and supplies $ 54 $ 53 Finished goods 2 3 Total $ 56 $ 56

DEBT (Tables)

DEBT (Tables)	3 Months Ended
	Mar. 31, 2018
DEBT
Schedule of Debt	Outstanding Principal (in millions) Interest Rate Maturity Security March 31, December 31, 2018 2017 Credit Agreements 2014 Revolving Credit Facility $ — $ 363 LIBOR plus 3.25%-4.00% June 30, 2021 Shared First-Priority Lien 2017 Credit Agreement 1,300 1,300 LIBOR plus 4.75% December 31, 2022 (a) Shared First-Priority Lien 2016 Credit Agreement 1,000 1,000 LIBOR plus 10.375% 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 5 1/2 % 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.

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	3 Months Ended
	Mar. 31, 2018
NONCONTROLLING INTERESTS
Schedule of changes in 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): Mezzanine Equity Equity – Noncontrolling Noncontrolling Interest 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

DERIVATIVES (Tables)

DERIVATIVES (Tables)	3 Months Ended
	Mar. 31, 2018
DERIVATIVES
Schedule of oil hedge positions	Q2 Q3 Q4 Q1 Q2 Q3 Q4 FY 2018 2018 2018 2019 2019 2019 2019 2020 Sold Calls: Barrels per day 6,168 6,127 16,086 16,057 6,023 991 503 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 11,023 991 503 Weighted-average price per barrel $ 45.83 $ 61.47 $ 45.85 $ 60.00 $ 60.05 $ 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.
Schedule of fair value (at gross and net) of outstanding derivatives	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 Gross Gross Net Fair Value Amounts Amounts Presented in Balance Sheet Recognized at Offset in the the Balance Classification Fair Value Balance Sheet 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 Gross Gross Net Fair Value Amounts Amounts Presented in Balance Sheet Recognized at Offset in the the Balance Classification Fair Value Balance Sheet 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)

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	3 Months Ended
	Mar. 31, 2018
EARNINGS PER SHARE
Calculation of basic and diluted EPS	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

PENSION AND POSTRETIREMENT BE31

PENSION AND POSTRETIREMENT BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2018
PENSION AND POSTRETIREMENT BENEFIT PLANS
Components of the net periodic benefit costs	Three months ended March 31, 2018 2017 Pension Postretirement Pension Postretirement Benefit Benefit Benefit 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

REVENUE RECOGNITION (Tables)

REVENUE RECOGNITION (Tables)	3 Months Ended
	Mar. 31, 2018
Schedule of disaggregated 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
ASU 2014-09
Schedule of the impact of the adoption of ASC 606 on our condensed consolidated statement of operations	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 Previous ASC 606 U.S. GAAP Change REVENUES AND OTHER Oil and gas sales $ 575 $ 568 $ 7 Net derivative losses (38) (38) — Other revenue 72 37 35 Total revenues and other 609 567 42 COSTS AND OTHER Production costs 212 212 — General and administrative expenses 63 63 — Depreciation, depletion and amortization 119 119 — Taxes other than on income 38 38 — Exploration expense 8 8 — Other expenses, net 61 19 42 Total costs and other 501 459 42 OPERATING (LOSS) INCOME 108 108 — NON-OPERATING (LOSS) INCOME Interest and debt expense, net (92) (92) — Other non-operating expenses (7) (7) — (LOSS) INCOME BEFORE INCOME TAXES 9 9 — Income tax benefit — — — NET (LOSS) INCOME 9 9 — Net (income) loss attributable to noncontrolling interests (11) (11) — NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK $ (2) $ (2) $ —

CONDENSED CONSOLIDATING FINAN33

CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2018
CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Schedule of Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheets Combined Combined Non- Guarantor Guarantor Parent Subsidiaries 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
Schedule of condensed consolidating statement of operations	Condensed Consolidating Statement of Operations Combined Combined Non- Guarantor Guarantor Parent Subsidiaries 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
Schedule of Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows Combined Combined Non- Guarantor Guarantor Parent Subsidiaries 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

THE SPIN-OFF AND BASIS OF PRE34

THE SPIN-OFF AND BASIS OF PRESENTATION - Separation and Spin off (Details)	Nov. 30, 2014
Spinoff - CRC | Occidental Petroleum
Separation and Spin Off Transactions
Percentage of outstanding shares of common stock initially retained by Occidental	18.50%

OTHER INFORMATION (Details)

OTHER INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Other current assets, net	$ 155		$ 130
Accrued liabilities	514		475
Interest paid, net of capitalized amounts	60	$ 44
Other current assets
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
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
Non-current asset retirement obligation	$ 407		$ 403

INVENTORIES (Details)

INVENTORIES (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
INVENTORIES
Materials and supplies	$ 54	$ 53
Finished goods	2	3
Total	$ 56	$ 56

DEBT - Schedule of long-term de

DEBT - Schedule of long-term debt (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 30, 2017	Mar. 31, 2018	Dec. 31, 2017
Debt
Long-term debt		$ 4,941	$ 5,306
2014 Revolving Credit Facility (Shared First Priority Lien)
Debt
Long-term debt			$ 363
2014 Revolving Credit Facility (Shared First Priority Lien) | Applicable margin on LIBOR loans | Minimum
Debt
Interest rate added to variable rate basis (as a percent)		3.25%	3.25%
2014 Revolving Credit Facility (Shared First Priority Lien) | Applicable margin on LIBOR loans | Maximum
Debt
Interest rate added to variable rate basis (as a percent)		4.00%	4.00%
2014 Revolving Credit Facility (Shared First Priority Lien) | Applicable margin on Alternate Base Rate loans | Minimum
Debt
Interest rate added to variable rate basis (as a percent)		2.25%	2.25%
2014 Revolving Credit Facility (Shared First Priority Lien) | Applicable margin on Alternate Base Rate loans | Maximum
Debt
Interest rate added to variable rate basis (as a percent)		3.00%	3.00%
2017 Credit Agreement (Shared First Priority Lien)
Debt
Long-term debt		$ 1,300	$ 1,300
2017 Credit Agreement (Shared First Priority Lien) | 91 days prior to maturity of 2016 Credit Agreement
Debt
Period before maturity of the specified notes that triggers accelerated payment	91 days
Outstanding amount of specified notes that triggers accelerated payment	$ 100
2017 Credit Agreement (Shared First Priority Lien) | Applicable margin on LIBOR loans
Debt
Interest rate added to variable rate basis (as a percent)		4.75%	4.75%
2017 Credit Agreement (Shared First Priority Lien) | Applicable margin on Alternate Base Rate loans
Debt
Interest rate added to variable rate basis (as a percent)		3.75%	3.75%
2016 Credit Agreement (Shared First Priority Lien)
Debt
Long-term debt		$ 1,000	$ 1,000
2016 Credit Agreement (Shared First Priority Lien) | Applicable margin on LIBOR loans
Debt
Interest rate added to variable rate basis (as a percent)		10.375%	10.375%
2016 Credit Agreement (Shared First Priority Lien) | Applicable margin on Alternate Base Rate loans
Debt
Interest rate added to variable rate basis (as a percent)		9.375%	9.375%
Second Lien Notes
Debt
Amount due in June 2021		$ 340
Amount due in December 2021		70
Amount due in June 2022		70
Second Lien Notes | 8% Notes Due 2022
Debt
Long-term debt		$ 2,248	$ 2,250
Debt instrument interest rate stated percentage		8.00%	8.00%
Senior Notes (Unsecured) | 5% Notes Due 2020
Debt
Long-term debt		$ 100	$ 100
Debt instrument interest rate stated percentage		5.00%	5.00%
Senior Notes (Unsecured) | 5.5% Notes Due 2021
Debt
Long-term debt		$ 100	$ 100
Debt instrument interest rate stated percentage		5.50%	5.50%
Senior Notes (Unsecured) | 6% Notes Due 2024
Debt
Long-term debt		$ 193	$ 193
Debt instrument interest rate stated percentage		6.00%	6.00%

DEBT - Deferred Gain and Issuan

DEBT - Deferred Gain and Issuance Costs (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
DEBT
Net deferred gain and issuance costs	$ 275	$ 287
Deferred gains	396	415
Deferred issuance costs	85	92
Original issue discount	$ 36	$ 36

DEBT - 2014 Revolving Credit Fa

DEBT - 2014 Revolving Credit Facility (Details) - 2014 Revolving Credit Facility - USD ($) $ in Millions	1 Months Ended
	May 31, 2018	Feb. 28, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt
Available borrowing capacity, subject to minimum liquidity requirement			$ 846
Minimum monthly liquidity			150
Borrowing base	$ 2,300
Letters of Credit
Debt
Maximum sub-limit on borrowing capacity for issuance of letters of credit			400
Aggregate letters of credit issued			$ 154	$ 148
Ares JV
Debt
Payments on long-term debt		$ 297
Amount borrowed		$ 1,000

DEBT - Repurchases and Fair Val

DEBT - Repurchases and Fair Value (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Apr. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
Repurchases of debt
Deferred issuance costs		$ 85	$ 92
Second Lien Notes
Repurchases of debt
Principal amount of debt reduction through payment or repurchase	$ 95
Repurchase value of the principal amounts	79
Pre-tax gain on extinguishment of debt	15
deferred issuance costs written-off	$ 1
Second Lien Notes | 8% Notes Due 2022
Repurchases of debt
Principal amount of debt reduction through payment or repurchase		$ 2
Debt instrument interest rate stated percentage		8.00%	8.00%
Repurchase value of the principal amounts		$ 1.6
Pre-tax gain on extinguishment of debt		$ 0.4

DEBT - Fair Value (Details)

DEBT - Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
DEBT
Estimated fair value of long-term debt	$ 4,400	$ 4,800
Debt carrying value	$ 4,941	$ 5,306

NONCONTROLLING INTERESTS - Chan

NONCONTROLLING INTERESTS - Changes in Noncontrolling Interests (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Balance	$ (720)	$ (557)
Contributions from noncontrolling interest holders, net	33	49
Distributions paid to noncontrolling interest holders	(15)
Balance	(654)	(447)
Noncontrolling Interest
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Balance	94
Net income (loss) attributable to noncontrolling interest	(3)
Contributions from noncontrolling interest holders, net	33	49
Distributions paid to noncontrolling interest holders	(15)
Balance	109	$ 48
Noncontrolling Interest | Ares JV
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Net income (loss) attributable to noncontrolling interest	1
Contributions from noncontrolling interest holders, net	33
Distributions paid to noncontrolling interest holders	(1)
Balance	33
Noncontrolling Interest | BSP JV
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Balance	94
Net income (loss) attributable to noncontrolling interest	(4)
Distributions paid to noncontrolling interest holders	(14)
Balance	$ 76

NONCONTROLLING INTERESTS - Mezz

NONCONTROLLING INTERESTS - Mezzanine Equity (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Mezzanine Equity - Redeemable Noncontrolling Interest - Ares
Balance	$ 724
Mezzanine Equity - Redeemable Noncontrolling Interest
Mezzanine Equity - Redeemable Noncontrolling Interest - Ares
Net income (loss) attributable to noncontrolling interest	14
Contributions from noncontrolling interest holders, net	714
Distributions to noncontrolling interest holders	(4)
Balance	$ 724

NONCONTROLLING INTERESTS - Othe

NONCONTROLLING INTERESTS - Other (Details) $ in Millions	1 Months Ended					3 Months Ended		5 Months Ended	12 Months Ended
	Feb. 28, 2018USD ($)MWMMcf	Jul. 31, 2017USD ($)item	Apr. 30, 2017USD ($)	Mar. 31, 2017USD ($)item	Feb. 28, 2017USD ($)	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Jul. 31, 2017USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
NONCONTROLLING INTERESTS
Net proceeds from the transaction						$ 747	$ 49
Transaction cost						85				$ 92
Amount used to fund capital investments						$ 139	$ 50
Ares JV
NONCONTROLLING INTERESTS
Transaction cost	$ 3
Ares JV | 2014 Revolving Credit Facility (Shared First Priority Lien)
NONCONTROLLING INTERESTS
Net proceeds from the transaction	$ 750
Class A common interest | Ares JV
NONCONTROLLING INTERESTS
Percentage of common interest held by CRC	50.00%
Period in which monthly distributions can be deferred	3 years
Class C common interest | Ares JV
NONCONTROLLING INTERESTS
Percentage of common interest held by CRC	95.25%
Natural gas power and Gas processing plants | Ares JV
NONCONTROLLING INTERESTS
Power plant capacity | MW	550
Gas processing plant capacity | MMcf	200
ECR Corporate Holdings L.P. | Class A common interest | Ares JV
NONCONTROLLING INTERESTS
Percentage of common interest held by non-controlling interests	50.00%
ECR Corporate Holdings L.P. | Class B preferred interest | Ares JV
NONCONTROLLING INTERESTS
Percentage of common interest held by non-controlling interests	100.00%
ECR Corporate Holdings L.P. | Class C common interest | Ares JV
NONCONTROLLING INTERESTS
Percentage of common interest held by non-controlling interests	4.75%
ECR | Redemption prior to fifth year
NONCONTROLLING INTERESTS
Redemption period						5 years
ECR | Redemption prior to fifth year | Class A common interest
NONCONTROLLING INTERESTS
Redemption price						$ 60
ECR | Redemption prior to fifth year | Class B preferred interest
NONCONTROLLING INTERESTS
Redemption price						$ 750
ECR | Redemption prior to seven and a half years
NONCONTROLLING INTERESTS
Maximum extension period of redemption						2 years 6 months
Whole payment redemption happen prior period						7 years 6 months
ECR | Redemption prior to seven and a half years | Class A common interest
NONCONTROLLING INTERESTS
Redemption price						$ 80
ECR | Redemption prior to seven and a half years | Class B preferred interest
NONCONTROLLING INTERESTS
Redemption price						750
Joint venture with BSP | BSP JV
NONCONTROLLING INTERESTS
Net proceeds from the transaction										98
Maximum commitment contribution					$ 250
Additional payment to redeem preferred interest					$ 0
Number of $50 commitments funded | item		2		2
Commitment contributed		$ 50		$ 50
Issuance fee								$ 2
Amount used to fund capital investments										96
Joint venture with MIRA | MIRA
NONCONTROLLING INTERESTS
Maximum commitment contribution			$ 300
Commitment contributed						$ 22				$ 58
Working interest acquired by MIRA (as a percent)			90.00%
Funding provided by MIRA for development of properties (as a percent)			100.00%
Working interest retained by CRC (as a percent)			10.00%
CRC's working interest if MIRA receives cash distributions equal to a predetermined threshold return (as a percent)			75.00%
Initial commitment			$ 160
Investment period of initial commitment			2 years
Joint venture with MIRA | MIRA | Expected
NONCONTROLLING INTERESTS
Commitment contributed									$ 75

DERIVATIVES - General (Details)

DERIVATIVES - General (Details)	Mar. 31, 2018bbl / d$ / bblbbl
Swaps | Q2 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	44,350
Weighted-average price (in dollars per barrel)	60
Swaps | Q3 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	19,000
Weighted-average price (in dollars per barrel)	60.13
Swaps | Q4 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	19,000
Weighted-average price (in dollars per barrel)	60.13
Swaps | Q1 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	7,000
Weighted-average price (in dollars per barrel)	67.71
Maximum increase in volume per quarter of crude oil counter-party swaps (in barrels per day) | bbl	5,000
Weighted-average Brent price (in dollars per barrel)	70
Swaps | Second half of 2018 production
Derivatives
Maximum increase in volume for the period of crude oil counterparties swaps (in barrels per day) | bbl	29,000
Weighted-average Brent price (in dollars per barrel)	60.50
Purchased | Calls | Q1 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	2,000
Weighted-average price (in dollars per barrel)	71
Purchased | Puts | Q2 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	1,168
Weighted-average price (in dollars per barrel)	45.83
Purchased | Puts | Q3 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	6,127
Weighted-average price (in dollars per barrel)	61.47
Purchased | Puts | Q4 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	1,086
Weighted-average price (in dollars per barrel)	45.85
Purchased | Puts | Q1 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	24,057
Weighted-average price (in dollars per barrel)	60
Purchased | Puts | Q2 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	11,023
Weighted-average price (in dollars per barrel)	60.05
Purchased | Puts | Q3 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	991
Weighted-average price (in dollars per barrel)	45.85
Purchased | Puts | Q4 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	961
Weighted-average price (in dollars per barrel)	45.85
Purchased | Puts | FY 2020
Derivatives
Daily Volume (in Bbl) | bbl / d	503
Weighted-average price (in dollars per barrel)	43.91
Sold | Calls | Q2 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	6,168
Weighted-average price (in dollars per barrel)	60.24
Sold | Calls | Q3 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	6,127
Weighted-average price (in dollars per barrel)	60.24
Sold | Calls | Q4 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	16,086
Weighted-average price (in dollars per barrel)	58.91
Sold | Calls | Q1 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	16,057
Weighted-average price (in dollars per barrel)	65.75
Sold | Calls | Q2 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	6,023
Weighted-average price (in dollars per barrel)	67.01
Sold | Calls | Q3 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	991
Weighted-average price (in dollars per barrel)	60
Sold | Calls | Q4 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	961
Weighted-average price (in dollars per barrel)	60
Sold | Calls | FY 2020
Derivatives
Daily Volume (in Bbl) | bbl / d	503
Weighted-average price (in dollars per barrel)	60
Sold | Puts | Q2 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	29,000
Weighted-average price (in dollars per barrel)	45
Sold | Puts | Q3 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	24,000
Weighted-average price (in dollars per barrel)	46.04
Sold | Puts | Q4 2018
Derivatives
Daily Volume (in Bbl) | bbl / d	19,000
Weighted-average price (in dollars per barrel)	45
Sold | Puts | Q1 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	25,000
Weighted-average price (in dollars per barrel)	49
Sold | Puts | Q2 2019
Derivatives
Daily Volume (in Bbl) | bbl / d	5,000
Weighted-average price (in dollars per barrel)	50

DERIVATIVES - Fair Value (Detai

DERIVATIVES - Fair Value (Details) - Commodity Contracts - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Presented in the Balance Sheet
Fair Value of Derivatives
Total derivatives	$ (126)	$ (133)
Presented in the Balance Sheet | Other current assets
Fair Value of Derivatives
Net Fair Value Presented in the Balance Sheet	44	23
Presented in the Balance Sheet | Other assets
Fair Value of Derivatives
Net Fair Value Presented in the Balance Sheet	7	1
Presented in the Balance Sheet | Accrued liabilities
Fair Value of Derivatives
Net Fair Value Presented in the Balance Sheet	(170)	(154)
Presented in the Balance Sheet | Other long-term liabilities
Fair Value of Derivatives
Net Fair Value Presented in the Balance Sheet	(7)	(3)
Recognized Fair Value
Fair Value of Derivatives
Total derivatives	(126)	(133)
Recognized Fair Value | Other current assets
Fair Value of Derivatives
Gross Amounts Recognized at Fair Value	52	39
Gross Amounts Offset in the Balance Sheet	(8)	(16)
Recognized Fair Value | Other assets
Fair Value of Derivatives
Gross Amounts Recognized at Fair Value	7	1
Recognized Fair Value | Accrued liabilities
Fair Value of Derivatives
Gross Amounts Recognized at Fair Value	(178)	(170)
Gross Amounts Offset in the Balance Sheet	8	16
Recognized Fair Value | Other long-term liabilities
Fair Value of Derivatives
Gross Amounts Recognized at Fair Value	$ (7)	$ (3)

EARNINGS PER SHARE - Calculatio

EARNINGS PER SHARE - Calculation of EPS (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
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
Weighed-average common shares outstanding - basic	44.2	42.3
Basic EPS (in dollars per share)	$ (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
Weighed-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 (in dollars per share)	$ (0.05)	$ 1.22
Weighted-average anti-dilutive shares	2.5	1.5

PENSION AND POSTRETIREMENT BE48

PENSION AND POSTRETIREMENT BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net periodic benefit costs:
Employer contributions to pension plan	$ 1	$ 4
Expected contribution to defined benefit pension plans during the reminder of 2018	3
Pension Benefit
Net periodic benefit costs:
Interest cost	1	1
Expected return on plan assets	(1)	(1)
Settlement loss	2	3
Net periodic benefit costs	2	3
Postretirement Benefit
Net periodic benefit costs:
Service cost	1	1
Interest cost	1	1
Net periodic benefit costs	$ 2	$ 2

REVENUE RECOGNITION - Commodity

REVENUE RECOGNITION - Commodity Sales Contracts and Marketing (Details)	3 Months Ended
	Mar. 31, 2018
REVENUE RECOGNITION
Term of payment following invoicing	30 days
Maximum duration of natural gas liquid contract (in years)	1 year

REVENUE RECOGNITION - Disaggreg

REVENUE RECOGNITION - Disaggregation of revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of revenue
Revenue from contract with customers	$ 575	$ 487
Other revenue	72	30
Interest income	1
Net derivative losses	(38)	73
Total revenues and other	609	$ 590
Oil
Disaggregation of revenue
Revenue from contract with customers	466
NGLs
Disaggregation of revenue
Revenue from contract with customers	63
Natural gas
Disaggregation of revenue
Revenue from contract with customers	46
Electricity
Disaggregation of revenue
Other revenue	24
Marketing
Disaggregation of revenue
Other revenue	$ 47

REVENUE RECOGNITION - Statement

REVENUE RECOGNITION - Statement of operations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUES AND OTHER
Oil and gas sales	$ 575	$ 487
Net derivative losses	(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 (LOSS) INCOME	108	115
NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(92)	(84)
Other non-operating expenses	(7)	(4)
INCOME BEFORE INCOME TAXES	9	52
NET (LOSS) INCOME	9	52
Net (income) loss attributable to noncontrolling interest	(11)	1
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	(2)	$ 53
ASU 2014-09 | Effect of Change Higher/(Lower)
REVENUES AND OTHER
Oil and gas sales	7
Other revenue	35
Total revenues and other	42
COSTS AND OTHER
Other expenses, net	42
Total costs and other	42
ASU 2014-09 | Balances without Adoption of ASC 606
REVENUES AND OTHER
Oil and gas sales	568
Net derivative losses	(38)
Other revenue	37
Total revenues and other	567
COSTS AND OTHER
Production costs	212
General and administrative expenses	63
Depreciation, depletion and amortization	119
Taxes other than on income	38
Exploration expense	8
Other expenses, net	19
Total costs and other	459
OPERATING (LOSS) INCOME	108
NON-OPERATING (LOSS) INCOME
Interest and debt expense, net	(92)
Other non-operating expenses	(7)
INCOME BEFORE INCOME TAXES	9
NET (LOSS) INCOME	9
Net (income) loss attributable to noncontrolling interest	(11)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	$ (2)

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) shares in Thousands, $ in Millions	Apr. 09, 2018USD ($)propertyshares	Apr. 02, 2018USD ($)	Mar. 31, 2018USD ($)employeeitem	Dec. 31, 2018USD ($)
SUBSEQUENT EVENTS
Approximate number of employees in Bakersfield | employee			500
Number of different locations in Bakersfield | item			9
Elk Hills Transaction
SUBSEQUENT EVENTS
Remaining commitments to invest an oil and gas property			$ 58
SUBSEQUENT EVENT | Office building
SUBSEQUENT EVENTS
Acquisition cost		$ 48.4
Term of occupying space as a tenant by former owner		8 months
SUBSEQUENT EVENT | Expected | Office building
SUBSEQUENT EVENTS
Rental income				$ 4
SUBSEQUENT EVENT | Maximum
SUBSEQUENT EVENTS
Expected period to bring all Bakersfield employees into single location		18 months
SUBSEQUENT EVENT | Minimum
SUBSEQUENT EVENTS
Expected period to bring all Bakersfield employees into single location		12 months
SUBSEQUENT EVENT | Elk Hills Transaction
SUBSEQUENT EVENTS
Number of and oil and gas properties in which evaluation and development activities are extended | property	1
Period of extension of evaluation and development activities	2 years
SUBSEQUENT EVENT | Registration Rights Agreement
SUBSEQUENT EVENTS
Number of business days to register common shares for resale after filling 10-Q	2 days
Maximum number of shares resale in first 30 days registration | shares	1,000
Maximum number of shares resale on after 30 days registration | shares	1,000
SUBSEQUENT EVENT | Elk Hills | Land
SUBSEQUENT EVENTS
Working interest held (as a percentage)	100.00%
Net revenue interest held (as a percentage)	100.00%
SUBSEQUENT EVENT | Working, surface and mineral interests | Elk Hills
SUBSEQUENT EVENTS
Acquisition cost	$ 510
Acquisition cost paid in cash	$ 460
Acquisition costs paid in common shares | shares	2,850

CONDENSED CONSOLIDATING FINAN53

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Balance sheets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Assets
Total current assets	$ 949	$ 483
Total property, plant and equipment, net	5,714	5,696
Other assets	36	28
TOTAL ASSETS	6,699	6,207
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	724
Total equity	(654)	(720)	$ (447)	$ (557)
TOTAL LIABILITIES AND EQUITY	6,699	6,207
Eliminations
Assets
Total current assets	(7)	(6)
Investments in consolidated subsidiaries	(5,145)	(5,711)
TOTAL ASSETS	(5,152)	(5,717)
Total current liabilities	(7)	(6)
Total equity	(5,145)	(5,711)
TOTAL LIABILITIES AND EQUITY	$ (5,152)	(5,717)
Maximum
Total consolidated assets held by Non-Guarantor Subsidiaries (as a percent)	1.00%
Parent | Reportable Legal Entity
Assets
Total current assets	$ 491	13
Total property, plant and equipment, net	23	24
Investments in consolidated subsidiaries	5,050	5,105
TOTAL ASSETS	5,564	5,142
Total current liabilities	125	122
Long-term debt	4,941	5,306
Deferred gain and issuance costs, net	275	287
Other long-term liabilities	153	154
Amounts due to (from) affiliates	833	87
Total equity	(763)	(814)
TOTAL LIABILITIES AND EQUITY	5,564	5,142
Combined Guarantor Subsidiaries | Reportable Legal Entity
Assets
Total current assets	414	464
Total property, plant and equipment, net	5,153	5,580
Investments in consolidated subsidiaries	95	606
Other assets	22	27
TOTAL ASSETS	5,684	6,677
Total current liabilities	680	613
Other long-term liabilities	448	445
Amounts due to (from) affiliates	(833)	(87)
Total equity	5,389	5,706
TOTAL LIABILITIES AND EQUITY	5,684	6,677
Combined Non-Guarantor Subsidiaries | Reportable Legal Entity
Assets
Total current assets	51	12
Total property, plant and equipment, net	538	92
Other assets	14	1
TOTAL ASSETS	603	105
Total current liabilities	8	3
Other long-term liabilities	6	3
Mezzanine equity	724
Total equity	(135)	99
TOTAL LIABILITIES AND EQUITY	$ 603	$ 105

CONDENSED CONSOLIDATING FINAN54

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK
Total revenues and other	$ 609	$ 590
Total costs and other	501	475
Non-operating (loss) income	(99)	(63)
NET (LOSS) INCOME	9	52
Net (income) loss attributable to noncontrolling interest	(11)	1
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	(2)	53
Reportable Legal Entity | Parent
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK
Total revenues and other	1
Total costs and other	44	53
Non-operating (loss) income	(98)	(81)
NET (LOSS) INCOME	(141)	(134)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	(141)	(134)
Reportable Legal Entity | Combined Guarantor Subsidiaries
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK
Total revenues and other	585	589
Total costs and other	460	420
Non-operating (loss) income	(1)	18
NET (LOSS) INCOME	124	187
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	124	187
Reportable Legal Entity | Combined Non-Guarantor Subsidiaries
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK
Total revenues and other	65	1
Total costs and other	39	2
NET (LOSS) INCOME	26	(1)
Net (income) loss attributable to noncontrolling interest	(11)	$ 1
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK	15
Eliminations
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK
Total revenues and other	(42)
Total costs and other	$ (42)

CONDENSED CONSOLIDATING FINAN55

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net cash (used) provided by operating activities	$ 200	$ 133
Net cash used in investing activities	(138)
Net cash provided (used) by financing activities	412	(95)
Increase (decrease) 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
Parent | Reportable Legal Entity
Net cash (used) provided by operating activities	(154)	(139)
Net cash used in investing activities	(1)	(1)
Net cash provided (used) by financing activities	633	140
Increase (decrease) in cash and cash equivalents	478
Cash and cash equivalents-beginning of period	7
Cash and cash equivalents-end of period	485
Combined Guarantor Subsidiaries | Reportable Legal Entity
Net cash (used) provided by operating activities	327	274
Net cash used in investing activities	(136)	1
Net cash provided (used) by financing activities	(199)	(284)
Increase (decrease) in cash and cash equivalents	(8)	(9)
Cash and cash equivalents-beginning of period	8	12
Cash and cash equivalents-end of period		3
Combined Non-Guarantor Subsidiaries | Reportable Legal Entity
Net cash (used) provided by operating activities	27	(2)
Net cash used in investing activities	(1)
Net cash provided (used) by financing activities	(22)	49
Increase (decrease) in cash and cash equivalents	4	47
Cash and cash equivalents-beginning of period	5
Cash and cash equivalents-end of period	$ 9	$ 47