California Resources Corp - Quarter Report: 2017 March (Form 10-Q)

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission file number 001-36478

_____________________

California Resources Corporation

(Exact name of registrant as specified in its charter)



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

9200 Oakdale Avenue, Suite 900 Los Angeles, California (Address of principal executive offices)		91311 (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

_____________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. (See definition of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act):

Large Accelerated Filer ¨ Accelerated Filer þ Non-Accelerated Filer ¨ Smaller Reporting Company ¨

Emerging Growth Company ¨

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

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



Shares of common stock outstanding as of March 31, 2017	42,592,983

California Resources Corporation and Subsidiaries

Table of Contents



	Page
Part I
Item 1	Financial Statements (unaudited)	2
	Consolidated Condensed Balance Sheets	2
	Consolidated Condensed Statements of Operations	3
	Consolidated Condensed Statements of Comprehensive Income	4
	Consolidated Condensed Statements of Cash Flows	5
	Notes to Consolidated Condensed Financial Statements	6
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	General	16
	Business Environment and Industry Outlook	16
	Seasonality	17
	Operations	18
	Fixed and Variable Costs	18
	Production and Prices	20
	Balance Sheet Analysis	21
	Statement of Operations Analysis	22
	Liquidity and Capital Resources	25
	Cash Flow Analysis	30
	2017 Capital Program	31
	Lawsuits, Claims, Contingencies and Commitments	31
	Significant Accounting and Disclosure Changes	32
	Safe Harbor Statement Regarding Outlook and Forward-Looking Information	32
Item 3	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4	Controls and Procedures	34

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

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

As of March 31, 2017 and December 31, 2016

(in millions, except share data)



	March 31,			December 31,
	2017			2016

CURRENT ASSETS

Cash and cash equivalents	$	50		$	12
Trade receivables, net	212			232
Inventories	57			58
Other current assets, net	90			123
Total current assets	409			425

PROPERTY, PLANT AND EQUIPMENT	20,963			20,915
Accumulated depreciation, depletion and amortization	(15,170		)	(15,030		)
Total property, plant and equipment	5,793			5,885

OTHER ASSETS	35			44

TOTAL ASSETS	$	6,237		$	6,354



CURRENT LIABILITIES

Current maturities of long-term debt	$	100		$	100
Accounts payable	238			219
Accrued liabilities	350			407
Total current liabilities	688			726

LONG-TERM DEBT - PRINCIPAL AMOUNT	5,021			5,168

DEFERRED GAIN AND ISSUANCE COSTS, NET	382			397

OTHER LONG-TERM LIABILITIES	593			620

EQUITY

Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at March 31, 2017 and December 31, 2016	—			—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (March 31, 2017 - 42,592,983 and December 31, 2016 - 42,542,637)	—			—
Additional paid-in capital	4,867			4,861
Accumulated deficit	(5,351		)	(5,404		)
Accumulated other comprehensive loss	(11		)	(14		)

Total equity attributable to common stock	(495		)	(557		)
Noncontrolling interest	48			—
Total equity	(447		)	(557		)

TOTAL LIABILITIES AND EQUITY	$	6,237		$	6,354

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Operations

For the three months ended March 31, 2017 and 2016

(in millions, except share data)



	Three months ended March 31,
	2017			2016
REVENUES AND OTHER
Oil and gas net sales	$	487		$	329
Net derivative gains (losses)	73			(25		)
Other revenue	30			18
Total revenues and other	590			322

COSTS AND OTHER
Production costs	211			184
General and administrative expenses	67			67
Depreciation, depletion and amortization	140			147
Taxes other than on income	33			39
Exploration expense	6			5
Other expenses, net	22			23
Total costs and other	479			465

OPERATING INCOME (LOSS)	111			(143		)

NON-OPERATING INCOME (LOSS)
Interest and debt expense, net	(84		)	(74		)
Net gains on early extinguishment of debt	4			89
Gains on asset divestitures	21			—
INCOME (LOSS) BEFORE INCOME TAXES	52			(128		)
Income tax benefit	—			78
NET INCOME (LOSS)	52			(50		)
Net (income) loss attributable to noncontrolling interest	1			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	53		$	(50	)

Earnings (loss) per share of common stock
Basic	$	1.23		$	(1.30	)
Diluted	$	1.22		$	(1.30	)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Comprehensive Income

For the three months ended March 31, 2017 and 2016

(in millions)



	Three months ended March 31,
	2017		2016
Net income (loss)	$	52	$	(50	)
Net (income) loss attributable to noncontrolling interest	1		—
Other comprehensive income items:
Reclassification to income of realized losses on pension and postretirement^(a)	3		3
Total other comprehensive income, net of tax	3		3
Comprehensive income (loss) attributable to common stock	$	56	$	(47	)


(a)	No associated tax for the three months ended March 31, 2017 and 2016. See Note 10, Retirement and Postretirement Benefit Plans, for additional information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Cash Flows

For the three months ended March 31, 2017 and 2016

(in millions)



	Three months ended March 31,
	2017			2016
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	52		$	(50	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	140			147
Deferred income tax benefit	—			(78		)
Net derivative (gains) losses	(73		)	25
Net (payments) proceeds on settled derivatives	(1		)	56
Net gains on early extinguishment of debt	(4		)	(89		)
Deferred gain and issuance costs amortization	(12		)	(15		)
Gains on asset divestitures	(21		)	—
Other non-cash losses in income, net	9			21
Dry hole expenses	1			—
Changes in operating assets and liabilities, net	42			98
Net cash provided by operating activities	133			115

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(50		)	(21		)
Changes in capital investment accruals	17			(7		)
Asset divestitures	33			—
Acquisitions and other	—			(1		)
Net cash used by investing activities	—			(29		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from revolving credit facility	221			361
Repayments of revolving credit facility	(299		)	(405		)
Payments on first-lien first-out term loan	(41		)	(25		)
Debt repurchases	(24		)	(13		)
Debt transaction costs	(2		)	(7		)
Contribution from noncontrolling interest, net	49			—
Issuance of common stock	1			1
Net cash used by financing activities	(95		)	(88		)
Increase (decrease) in cash and cash equivalents	38			(2		)
Cash and cash equivalents—beginning of period	12			12
Cash and cash equivalents—end of period	$	50		$	10

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Condensed Financial Statements

March 31, 2017

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 and we became an independent, publicly traded company (the Spin-off). Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which it distributed to Occidental stockholders on March 24, 2016.

Except when the context otherwise requires or where otherwise indicated, (1) all references to ‘‘CRC,’’ the ‘‘company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries or the California business, (2) all references to the ‘‘California business’’ refer to Occidental’s California oil and gas exploration and production operations and related assets, liabilities and obligations, which we have assumed in connection with the Spin-off, and (3) 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, 2017 and the statements of operations, comprehensive income, and cash flows for the three months ended March 31, 2017 and 2016, as applicable. We have eliminated all of our significant intercompany transactions and accounts.

We have prepared this report pursuant to the rules and regulations of the United States (U.S.) Securities and Exchange Commission 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 and combined financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2016.

Certain prior year amounts have been reclassified to conform to the 2017 presentation. We reclassified net derivative gains (losses) out of other revenue to its own line item. Prior period gains (losses) on debt transactions were reclassified from other expenses, net to net gains on early extinguishment of debt. Also, debt repurchase and amendment costs were separated into debt repurchases and debt transaction costs on the statements of cash flows.

We completed a reverse stock split on May 31, 2016, using a ratio of one share of common stock for every ten shares then outstanding. Share and per share amounts included in this report have been restated to reflect this reverse stock split.


NOTE 2	ACCOUNTING AND DISCLOSURE CHANGES

Recently Issued Accounting and Disclosure Changes

In January 2017, the Financial Accounting Standards Board (FASB) issued new rules that changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

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 will 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. The rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

Recently Adopted Accounting and Disclosure Changes

In July 2015, the FASB issued rules requiring entities to measure inventory at the lower of cost or net

realizable value. We adopted these rules in the first quarter of 2017 with no changes to our financial statements.


NOTE 3	OTHER INFORMATION

Other current assets, net at March 31, 2017 and December 31, 2016 included amounts due from joint interest partners, net, of approximately $42 million and $51 million and derivative assets from commodities contracts of $34 million and $39 million, respectively.

Accrued liabilities at March 31, 2017 and December 31, 2016 reflected greenhouse gas obligations of $94 million and $89 million, accrued interest of $77 million and $25 million, accrued employee-related costs of $44 million and $91 million and derivative liabilities from commodities contracts of $39 million and $103 million, respectively.

Other long-term liabilities included asset retirement obligations of $402 million and $397 million at March 31, 2017 and December 31, 2016, 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-month periods ended March 31, 2017 and 2016. Interest paid totaled approximately $44 million and $48 million for the three months ended March 31, 2017 and 2016, respectively.

NOTE 4 INVENTORIES

Inventories as of March 31, 2017 and December 31, 2016 consisted of the following:



	March 31, 2017		December 31, 2016
	(in millions)
Materials and supplies	$	54	$	55
Finished goods	3		3
Total	$	57	$	58

NOTE 5 DEBT

Debt as of March 31, 2017 and December 31, 2016 consisted of the following:



	March 31, 2017			December 31, 2016
	(in millions)
2014 First-Out Credit Facilities (Secured First Lien)
Revolving Credit Facility	$	769		$	847
Term Loan Facility	609			650
2016 Second-Out Credit Agreement (Secured First Lien)	1,000			1,000
Senior Notes (Secured Second Lien)
8% Notes Due 2022	2,250			2,250
Senior Unsecured Notes
5% Notes Due 2020	165			193
5 ½% Notes Due 2021	135			135
6% Notes Due 2024	193			193
Total Debt - Principal Amount	5,121			5,268
Less Current Maturities of Long-Term Debt	(100		)	(100		)
Long-Term Debt - Principal Amount	$	5,021		$	5,168

At March 31, 2017, deferred gain and issuance costs were $382 million net, consisting of $471 million of deferred gains offset by $89 million of deferred issuance costs and original issue discounts. The December 31, 2016 deferred gain and issuance costs were $397 million net, consisting of $489 million of deferred gains offset by $92 million of deferred issuance costs and original issue discounts.

Credit Facilities

2014 First-Out Credit Facilities

Our first-lien, first-out credit facilities (2014 First-Out Credit Facilities) comprise (i) a $609 million senior term loan facility (the Term Loan Facility) and (ii) a $1.4 billion senior revolving loan facility (the Revolving Credit Facility). We are permitted to increase the size of the Revolving Credit Facility by up to $250 million if we obtain additional commitments from new or existing lenders. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit. Our credit limit under the 2014 First-Out Credit Facilities is $2.01 billion. Borrowings under these facilities are also subject to a borrowing base, which was reaffirmed at $2.3 billion as of May 1, 2017.

As of March 31, 2017 and December 31, 2016, we had outstanding borrowings of $769 million and $847 million under our Revolving Credit Facility, and $609 million and $650 million under the Term Loan Facility, respectively. In each of the quarters ended March 31, 2017 and 2016, we made a $25 million scheduled quarterly payment on the Term Loan Facility. Additionally, in February 2017, we made a $16 million Term Loan Facility prepayment from the proceeds of non-core asset sales.

In February 2017, we amended the 2014 First-Out Credit Facilities to facilitate additional joint venture transactions and note repurchases, eliminate our capital expenditure restriction and adopt a minimum liquidity covenant.

We have granted the lenders under the 2014 First-Out Credit Facilities a first-priority lien in a substantial majority of our assets, including our Elk Hills power plant and midstream assets. We also granted a lien in the same assets to the lenders under our first-lien, second-out term loan credit facility (2016 Second-Out Credit Agreement) and the holders of our 8% senior secured second-lien notes due December 15, 2022 (2022 notes).

Borrowings under the 2014 First-Out Credit Facilities bear interest, at our election, at either a LIBOR rate or an alternate base rate (ABR) (equal to the highest of (i) the federal funds effective rate plus 0.50%, (ii) the administrative agent’s prime rate and (iii) the one-month LIBOR rate plus 1.00%), in each case plus an applicable margin. This applicable margin is based, while our total leverage ratio exceeds 3.00:1.00, on our borrowing base utilization and will vary from (a) in the case of LIBOR loans, 2.50% to 3.50% and (b) in the case of ABR loans, 1.50% to 2.50%. The unused portion of the Revolving Credit Facility commitments is subject to a commitment fee equal to 0.50% per annum. We also pay customary fees and expenses under the 2014 First-Out Credit Facilities. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly.

Our financial performance covenants under the 2014 First-Out Credit Facilities require that (i) the ratio of our first-lien, first-out secured debt to trailing four quarter EBITDAX (the First-Lien First-Out Leverage Ratio) not exceed 3.50 to 1.00 at March 31 and June 30, 2017 and 3.25 to 1.00 at September 30 and December 31, 2017 and (ii) the total interest expense coverage ratio at each quarter end not be less than 1.20 to 1.00 through the quarter ending December 31, 2017. Beginning with the end of the first quarter of 2018, the First-Lien First-Out Leverage Ratio may not exceed 2.25 to 1.00 and the total interest expense coverage ratio may not be less than 2.00 to 1.00. The covenants also include a requirement that our first-lien asset coverage ratio must be at least 1.20 to 1.00 as of each June 30 and December 31 and a requirement that minimum monthly liquidity be not less than $250 million as of the last day of any calendar month. As of March 31, 2017, we had approximately $500 million of available borrowing capacity, subject to the minimum liquidity requirement.

We must generally apply 100% of the net cash proceeds from asset sales (other than permitted development joint ventures) to repay loans outstanding under the 2014 First-Out Credit Facilities, except that we are permitted to use up to 50% of net cash proceeds from non-borrowing base asset sales or monetizations (i) to repurchase our notes to the extent available at a significant minimum discount to par, as specified in the facilities, (ii) to purchase up to $140 million of certain of our unsecured notes at a discount, (iii) for general corporate purposes or (iv) for oil and gas expenditures. At least 75% of asset sale proceeds must be in cash (50% for sales of non-borrowing base assets unless our leverage ratio is less than 4:00 to 1:00 at which time the requirement falls to 40%), other than permitted development joint ventures and certain other transactions. The 2014 First-Out Credit Facilities also permit us to incur up to an additional $50 million of non-facility indebtedness, which may be secured by non-borrowing base assets, subject to compliance with our financial covenants and indentures, the proceeds of which must be applied to repay the Term Loan Facility. We must apply cash on hand in excess of $150 million daily to repay amounts outstanding under our Revolving Credit Facility. Further, we are restricted from paying dividends or making other distributions to common stockholders.

Our borrowing base under the 2014 First-Out Credit Facilities is redetermined each May 1 and November 1. The borrowing base is based upon a number of factors, including commodity prices and reserves. Increases in our borrowing base require approval of at least 80% of our revolving lenders, as measured by exposure, while decreases or affirmations require a two-thirds approval. We and the lenders (requiring a request from the lenders holding two-thirds of the revolving commitments and outstanding loans) each may request a special redetermination once in any period between three consecutive scheduled redeterminations. We will be permitted to have collateral released when both (i) our credit ratings are at least Baa3 from Moody's and BBB- from S&P, in each case with a stable or better outlook, and (ii) certain permitted liens securing other debt are released.

2016 Second-Out Credit Agreement

In August 2016, we entered into a $1 billion 2016 Second-Out Credit Agreement. The net borrowings under the 2016 Second-Out Credit Agreement were used to (i) prepay $250 million of the Term Loan Facility and (ii) reduce our Revolving Credit Facility by $740 million. The proceeds received were net of a $10 million original issue discount. The loan under the 2016 Second-Out Credit Agreement bears interest at a floating rate per annum equal to LIBOR plus 10.375%, subject to a 1.00% LIBOR floor, determined for the applicable interest period (or ABR rates plus 9.375% in certain circumstances). Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly. Interest on ABR loans is payable quarterly in arrears.

The 2016 Second–Out Credit Agreement matures at the earlier of December 2021 and the 91^st day prior to maturity of the 2020 notes and 5 ½% senior unsecured notes due September 15, 2021 (2021 notes) if the outstanding principal amount of either series exceeds $100 million prior to its respective maturity date. As of March 31, 2017, we had $165 million and $135 million in aggregate principal amount of outstanding 2020 notes and 2021 notes, respectively.

The 2016 Second-Out Credit Agreement is secured by a security interest in the same collateral used to secure the 2014 First-Out Credit Facilities, but, under intercreditor arrangements with the 2014 First-Out Credit Facilities lenders, are second in collateral recovery behind such lenders. Prepayment of the 2016 Second-Out Credit Agreement is subject to a make-whole premium prior to the third anniversary of closing and a premium to par equal to 50% of coupon between the third anniversary and the fourth anniversary. Following the fourth anniversary, we may redeem at par. At both March 31, 2017 and December 31, 2016, we had $1 billion outstanding under the 2016 Second-Out Credit Agreement.

The 2016 Second-Out Credit Agreement provides for customary covenants and events of default consistent with, or generally less restrictive than, the covenants in the 2014 First-Out Credit Facilities, including limitations on additional indebtedness, liens, asset dispositions, investments and restricted payments and other negative covenants, in each case subject to certain limitations and exceptions. Additionally, the 2016 Second-Out Credit Agreement requires us to maintain a first-lien asset coverage ratio of 1.20 to 1.00 as of any June 30 and December 31, consistent with the 2014 First-Out Credit Facilities.

Senior Notes

In October 2014, we issued $5 billion in aggregate principal amount of our senior unsecured notes, including $1 billion of 2020 notes, $1.75 billion of 2021 notes and $2.25 billion of 6% senior unsecured notes due November 15, 2024 (2024 notes, and collectively, the unsecured notes). We used the net proceeds from the issuance of the unsecured notes to make a $4.95 billion cash distribution to Occidental in October 2014.

In December 2015, we issued $2.25 billion in aggregate principal amount of our 2022 notes which we exchanged for $2.8 billion of our outstanding unsecured notes. We recorded a deferred gain of approximately $560 million on the debt exchange, which will be amortized using the effective interest rate method over the term of the 2022 notes. Our 2022 notes are secured on a second-priority basis, subject to the terms of an intercreditor agreement and collateral trust agreement, by a lien on the same collateral used to secure our obligations under the 2014 First-Out Credit Facilities and 2016 Second-Out Credit Agreement (collectively, the Credit Facilities).

In December 2015, we repurchased approximately $33 million in principal amount of the 2020 notes for $13 million in cash.

In 2016, we repurchased over $1.5 billion of our outstanding unsecured notes, primarily using drawings of $750 million on our Revolving Credit Facility and cash from operations. We also exchanged approximately 3.4 million shares of our common stock for unsecured notes in an aggregate principal amount of over $100 million.

In the first quarter of 2017, we repurchased $28 million in aggregate principal amount of our 2020 notes for $24 million, resulting in a $4 million pre-tax gain, net of related expenses. The first quarter of 2016 included an $89 million pre-tax gain resulting from the repurchase of notes in that quarter.

We will pay interest semiannually in cash in arrears on January 15 and July 15 for the 2020 notes, on March 15 and September 15 for the 2021 notes, on June 15 and December 15 for the 2022 notes and on May 15 and November 15 for the 2024 notes.

The indentures governing the unsecured notes and the 2022 notes each include covenants that, among other things, limit our and our subsidiaries’ ability to incur debt secured by liens. The indentures also restrict our ability to merge or consolidate with, or transfer all or substantially all of our assets to, another entity. The covenants are not, however, directly linked to measures of our financial performance. In addition, if we experience a “change of control triggering event” (as defined in the indentures) with respect to a series of notes, we will be required, unless we have exercised our right to redeem the notes of such series, to offer to purchase the notes of such series at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest. The indenture governing the 2022 notes also restricts our ability to sell certain assets and to release collateral from liens securing the 2022 notes, unless the collateral is released in compliance with the 2014 First-Out Credit Facilities.

We may redeem the unsecured notes prior to their maturity dates, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed plus a make-whole amount and accrued and unpaid interest.

We may redeem the 2022 notes (i) prior to December 15, 2017 from the proceeds of certain equity offerings, in an amount up to 35% of the initial aggregate principal amount of the notes initially issued plus any additional notes issued, at a redemption price equal to 108% of the principal amount redeemed, plus accrued and unpaid interest (ii) prior to December 15, 2018, in whole or in part at a redemption price equal to 100% of the principal amount redeemed plus a make-whole amount and accrued and unpaid interest and (iii) on or after December 15, 2018, in whole or in part at a fixed redemption price during 2018, 2019 and thereafter of 104%, 102% and 100% of the principal amount redeemed, respectively, plus accrued and unpaid interest.

Other

All obligations under the Credit Facilities and the notes are guaranteed both fully and unconditionally and jointly and severally by all of our material wholly owned subsidiaries. The assets and liabilities, results from operations and cash flows of our operating subsidiaries not guaranteeing the debt are de minimis. A joint venture that we entered into with Benefit Street Partners (BSP) was funded in mid-March 2017 and is not a subsidiary guarantor.

The terms and conditions of all of our indebtedness are subject to additional qualifications and limitations that are set forth in the relevant governing documents.

At March 31, 2017, we were in compliance with all the financial and other covenants under our Credit Facilities.

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, 2017 and December 31, 2016, including the fair value of the variable rate portion, was approximately $4.6 billion and $4.9 billion, respectively, compared to a carrying value of approximately $5.1 billion and $5.3 billion. A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on March 31, 2017 would result in a $3 million change in annual interest expense.

As of March 31, 2017 and December 31, 2016, we had letters of credit of approximately $130 million under the Revolving Credit Facility. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.


NOTE 6	ACQUISITIONS, DIVESTITURES AND OTHER

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

In February 2017, we entered into a joint venture with BSP under which BSP will invest up to $250 million, subject to agreement of the parties, to be used to develop certain of our oil and gas properties in exchange for our contribution of a net profits interest (NPI) in existing and future production from such properties. If BSP receives cash distributions equal to a predetermined threshold return, the NPI reverts to us. BSP contributed its initial commitment of $50 million in the first quarter of 2017. Approximately $47 million remained in cash and cash equivalents at March 31, 2017 and was designated to be used for capital investments related to this joint venture. Our consolidated financial statements reflect this joint venture as a noncontrolling interest.

In April 2017, we entered into a joint venture with Macquarie Infrastructure and Real Assets Inc. (MIRA) under which MIRA will invest up to $300 million, subject to agreement of the parties, to develop certain of our oil and gas properties in exchange for a 90% working interest in the related properties. MIRA will fund 100% of the development cost of such properties. If MIRA receives cash distributions equal to a predetermined threshold return, our working interest reverts to 75%. MIRA initially committed $160 million, which is intended to be invested over two years.

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.

The previously disclosed purported class action against us relating to the Trust Indenture Act of 1939 was dismissed in April 2017.

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, 2017 and December 31, 2016 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, 2017, we are not aware of material indemnity claims pending or threatened against the company.

We are currently under examination by the Internal Revenue Service for our U.S. federal income tax return for the post-Spin-off period in 2014 and calendar year 2015. No significant issues have been raised to date. State returns for these years remain subject to examination.

NOTE 8 DERIVATIVES

General

We use a variety of derivative instruments to protect our cash flows, margins and capital investment program from the cyclical nature of commodity prices and to improve our ability to comply with the covenants of our credit facilities in case of further 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, 2017, 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, 2017:



	Q2 2017		Q3 2017		Q4 2017		Q1 2018		Q2 - Q4 2018		FY 2019		FY 2020
Crude Oil
Calls:
Barrels per day	5,600		10,600		15,600		16,200		15,500		500		400
Weighted-average price per barrel	$	55.60	$	56.37	$	56.26	$	58.81	$	58.87	$	60.00	$	60.00

Puts:
Barrels per day	20,600		17,600		10,600		600		500		500		400
Weighted-average price per barrel	$	50.24	$	50.85	$	48.11	$	50.00	$	50.00	$	50.00	$	50.00

Swaps:
Barrels per day	20,000		25,000		25,000		—		—		—		—
Weighted-average price per barrel	$	53.98	$	54.99	$	54.99	$	—	$	—	$	—	$	—

A small portion of these derivatives are attributable to BSP's noncontrolling interest, including all the 2019 and 2020 positions. Some of our third and fourth quarter 2017 crude oil swaps grant our counterparties quarterly options to increase volumes by up to 10,000 barrels per day for each quarter at a weighted-average Brent price of $55.46. Our counterparties also have options to further increase volumes for the second half of 2017 by up to 10,000 barrels per day at a weighted-average Brent price of $60.24.

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, 2017 and December 31, 2016 (in millions):



	March 31, 2017
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheet			Net Fair Value Presented in the Balance Sheet
Assets
Commodity Contracts	Other current assets	$	48		$	(14	)	$	34
Commodity Contracts	Other assets	9			—			9

Liabilities
Commodity Contracts	Accrued liabilities	(53		)	14			(39		)
Commodity Contracts	Other long-term liabilities	(24		)	—			(24		)
Total derivatives		$	(20	)	$	—		$	(20	)

The above table includes amounts related to the noncontrolling interest.



	December 31, 2016
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheet			Net Fair Value Presented in the Balance Sheet
Assets
Commodity Contracts	Other current assets	$	88		$	(49	)	$	39
Commodity Contracts	Other assets	25			(6		)	19

Liabilities
Commodity Contracts	Accrued liabilities	(152		)	49			(103		)
Commodity Contracts	Other long-term liabilities	(58		)	6			(52		)
Total derivatives		$	(97	)	$	—		$	(97	)

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 they do not share in losses. For basic EPS, the weighted-average number of common shares outstanding excludes outstanding shares related to unvested stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially dilutive securities.

On May 31, 2016, we completed a reverse stock split using a ratio of one share of common stock for every ten shares then outstanding. Share and per share amounts included in this report have been restated for all periods presented to reflect this stock split.

For the three months ended March 31, 2017 and 2016, we issued approximately 42,000 shares and 98,000 shares, respectively, of common stock in connection with our employee stock purchase plan.

The following table presents the calculation of basic and diluted EPS for the three months ended March 31, 2017 and 2016:



	Three months ended March 31,
	2017			2016
	(in millions, except per-share amounts)
Basic EPS calculation
Net income (loss) attributable to common stock	$	53		$	(50	)
Less: net income (loss) allocated to participating securities	(1		)	—
Net income (loss) available to common stockholders	$	52		$	(50	)

Weighted-average common shares outstanding - basic	42.3			38.5
Basic EPS	$	1.23		$	(1.30	)

Diluted EPS calculation
Net income (loss) attributable to common stock	$	53		$	(50	)
Less: net income (loss) allocated to participating securities	(1		)	—
Net income (loss) available to common stockholders	$	52		$	(50	)

Weighted-average common shares outstanding - basic	42.3			38.5
Dilutive effect of potentially dilutive securities	0.3			—
Weighted-average common shares outstanding - diluted	42.6			38.5
Diluted EPS	$	1.22		$	(1.30	)

NOTE 10 RETIREMENT 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,
	2017					2016
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	—		$	1	$	—		$	1
Interest cost	1			1		1			1
Expected return on plan assets	(1		)	—		(1		)	—
Settlement loss	3			—		3			—
Total	$	3		$	2	$	3		$	2

During the three months ended March 31, 2017 and 2016, we contributed $4 million and $5 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 2017. The 2017 and 2016 settlements were associated with early retirements.

NOTE 11 INCOME TAXES

For the three months ended March 31, 2017, we did not provide any current or deferred tax provision on pre-tax income of $52 million because we have a full valuation allowance against our net deferred tax asset. Given our recent and anticipated future earnings trends, we do not believe any of our valuation allowance as of March 31, 2017 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. For the same period of 2016, we had a deferred tax benefit of $78 million resulting from a change in valuation allowance.


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

Except when the context otherwise requires or where otherwise indicated, (1) all references to ‘‘CRC,’’ the ‘‘company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries or the California business, (2) all references to the ‘‘California business’’ refer to Occidental’s California oil and gas exploration and production operations and related assets, liabilities and obligations, which we have assumed in connection with the Spin-off discussed below, and (3) all references to ‘‘Occidental’’ refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries.

General

Business Environment and Industry Outlook

Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly, generally as a result of changes in supply and demand and other market-related variables. These and other factors make it impossible to predict realized prices reliably.

Much of the global exploration and production industry has been challenged at prevailing price levels in recent years, putting pressure on the industry's ability to generate positive cash flow and access capital. Global oil prices improved beginning in the second quarter of 2016 through the first quarter of 2017 and began to trade in a narrower range. Natural gas liquids (NGLs) prices have improved relative to crude oil prices since early 2016 due to tighter domestic supplies, the strength of exports and higher contract prices on natural gasoline. Natural gas prices in the U.S. were higher in the three months ended March 31, 2017 than the comparable period in 2016 due to lower production and higher demand.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2017 and 2016:



	Three months ended March 31,
	2017		2016
Brent oil ($/Bbl)	$	54.66	$	35.08
WTI oil ($/Bbl)	$	51.91	$	33.45
NYMEX gas ($/MMBtu)	$	3.26	$	2.07

Oil prices and differentials will continue to be affected by a variety of factors including consumption patterns; inventory levels; global and local economic conditions; the actions of OPEC and other producers and governments; actual or threatened disruptions in production, refining and processing; currency exchange rates; worldwide drilling and exploration activities; the effects of conservation, weather, geophysical and technical limitations; transportation limitations; technological advances; and regional market conditions and costs in producing areas; as well as the effect of changes in these variables on market perceptions.

We currently sell all of our crude oil into the California refining markets, which we believe have offered relatively favorable pricing compared to other U.S. regions for similar grades. California is heavily reliant on imported sources of energy, with approximately 67% of the oil consumed in recent years imported from outside the state. A vast majority of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades. We also opportunistically consider export markets to improve our margins.

Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Capacity influences prices because California imports about 90% of its natural gas from other parts of the U.S. As a result, we typically enjoy favorable pricing since we can deliver our gas for lower transportation costs. Due to much lower levels of natural gas production compared to our oil production, the changes in natural gas prices have a smaller impact on our operating results.

In addition to selling natural gas, we also use gas for our steamfloods and power generation. As a result, the positive impact of higher prices is partially offset by higher operating costs. Higher natural gas prices have a net positive effect on our operating results. Conversely, lower natural gas prices generally have a net negative effect on our operations, but lower the cost of our steamflood projects and power generation.

Our earnings are also affected by the performance of our processing and power generation assets. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Additionally, we use part of the electricity from our Elk Hills power plant to reduce operating costs to Elk Hills and nearby fields and increase reliability. The remaining electricity is sold to the grid and a utility under a power purchase and sales agreement that includes a capacity payment. The price we obtain for our excess power impacts our earnings but generally by an insignificant amount.

We opportunistically seek strategic hedging transactions to protect our cash flows, margins and capital investment programs from the cyclical nature of commodity prices and to improve our ability to comply with the covenants under our credit facilities. We can give no assurances that our hedges will be adequate to accomplish our objectives. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not necessarily accounted for as cash-flow or fair-value hedges.

We respond to economic conditions by adjusting the size and allocation of our capital program, aligning the size of our workforce with our level of activity, continuing to improve efficiencies and finding cost savings. The reductions in our capital program in 2015 and 2016 negatively impacted our production levels. Sustained low prices may materially affect the quantities of oil and gas reserves we can economically produce over the longer term.

Seasonality

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

Acquisitions, Divestitures and Other

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

In February 2017, we entered into a joint venture with Benefit Street Partners (BSP) under which BSP will invest up to $250 million, subject to agreement of the parties, to be used to develop certain of our oil and gas properties in exchange for our contribution of a net profits interest (NPI) in existing and future production from such properties. If BSP receives cash distributions equal to a predetermined threshold return, the NPI reverts to us. BSP contributed its initial commitment of $50 million in the first quarter of 2017. Approximately $47 million remained in cash and cash equivalents at March 31, 2017 and was designated to be used for capital investments related to this joint venture. Our consolidated financial statements reflect this joint venture as a noncontrolling interest.

Operations

We conduct our operations through fee interests, mineral leases and other contractual arrangements. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net acres, approximately 60% of which we hold in fee. Our oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. We also own a network of strategically placed infrastructure that is integrated with, and complementary to, our operations, including gas plants, oil and gas gathering systems, a power plant and other related assets, which we use to maximize the value generated from our production.

Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and production costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (1) to recover our partners’ share of capital and production costs that we incur on their behalf, (2) for our share of contractually defined base production and (3) for our share of production in excess of contractually defined base production for each period. We realize our share of capital and production costs, and generate returns, through our defined share of production from (2) and (3) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline assuming comparable capital investment and production costs; however, our net economic benefit is greater when product prices are higher. The contracts represented slightly less than 20% of our production for the quarter ended March 31, 2017. During 2016, the PSC representing the majority of the field's production adjusted to eliminate the base production sharing split. Our share of the base production was smaller than our share of excess production. Accordingly, we now receive a modestly larger share of total field production after cost recovery.

Fixed and Variable Costs

Our total production costs consist of variable costs that tend to vary depending on production levels, and fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. While a certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. Overall, we believe approximately one-third of our operating costs are fixed over the life cycle of our fields. We actively manage our fields to optimize production and costs. When we see growth in a field we increase capacities, and similarly when a field nears the end of its economic life we manage the costs while it remains economically viable to produce.

Production and Prices

The following table sets forth our average production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2017 and 2016:



	Three months ended March 31,
	2017	2016
Oil (MBbl/d)
San Joaquin Basin	54	60
Los Angeles Basin	27	32
Ventura Basin	5	6
Sacramento Basin	—	—
Total	86	98

NGLs (MBbl/d)
San Joaquin Basin	15	16
Los Angeles Basin	—	—
Ventura Basin	1	1
Sacramento Basin	—	—
Total	16	17

Natural gas (MMcf/d)
San Joaquin Basin	141	147
Los Angeles Basin	1	3
Ventura Basin	8	8
Sacramento Basin	31	38
Total	181	196

Total Production (MBoe/d)^(a)	132	148


Note:	MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent per day.

(a)

Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, for the three months ended March 31, 2017, the average prices of Brent oil and NYMEX natural gas were $54.66 per barrel and $3.26 per MMBtu, respectively, resulting in an oil-to-gas ratio of approximately 17 to 1.

The following table sets forth the average realized prices for our products:



	Three months ended March 31,
	2017		2016
Oil prices with hedge ($ per Bbl)	$	50.24	$	36.39

Oil prices without hedge ($ per Bbl)	$	50.40	$	30.08
NGLs prices ($ per Bbl)	$	34.33	$	16.39
Gas prices without hedge ($ per Mcf)	$	2.90	$	2.05

The following table presents our average realized prices as a percentage of Brent, WTI and NYMEX for the three months ended March 31, 2017 and 2016:



	Three months ended March 31,
	2017		2016
Oil with hedge as a percentage of Brent	92	%	104	%

Oil without hedge as a percentage of Brent	92	%	86	%
Oil without hedge as a percentage of WTI	97	%	90	%
Gas without hedge as a percentage of NYMEX	89	%	99	%

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2016 to March 31, 2017 are discussed below:



	March 31, 2017		December 31, 2016
	(in millions)
Cash and cash equivalents	$	50	$	12
Trade receivables, net	$	212	$	232
Inventories	$	57	$	58
Other current assets, net	$	90	$	123
Property, plant and equipment, net	$	5,793	$	5,885
Other assets	$	35	$	44



Current maturities of long-term debt	$	100		$	100
Accounts payable	$	238		$	219
Accrued liabilities	$	350		$	407
Long-term debt - principal amount	$	5,021		$	5,168
Deferred gain and issuance costs, net	$	382		$	397
Other long-term liabilities	$	593		$	620
Equity attributable to common stock	$	(495	)	$	(557	)
Equity attributable to noncontrolling interest	$	48		$	—

Cash and cash equivalents at March 31, 2017 included $47 million of cash designated to be used for capital investments related to our joint venture with BSP. See "Liquidity and Capital Resources" for additional discussion of changes in cash and cash equivalents.

The decrease in trade receivables was largely the result of lower net sales in March 2017 compared to December 2016. The decrease in other current assets, net was mainly due to the sale of a non-core asset, a reduction in the amounts due from joint interest partners and a decrease in the net value of our derivative assets. The decrease in property, plant and equipment reflected depreciation, depletion and amortization (DD&A) for the period, partially offset by capital investments. The decrease in other assets was primarily due to a reduction in the fair value of our long-term derivative assets.

The increase in accounts payable reflected higher capital investments and operating costs in the quarter ended March 31, 2017 compared to December 31, 2016. The decrease in accrued liabilities was primarily due to the reduction in fair value of outstanding derivatives and the effect of employee bonus payments in the first quarter of 2017, partially offset by increased interest accruals due to the timing of payments. Other long-term liabilities reflected lower derivative liabilities, primarily due to mark-to-market effects. The decrease in long-term debt reflected a reduction in amounts outstanding under our revolving credit facility, repurchases of a portion of our unsecured notes and payments on our first-lien, first-out term loan. The decrease in deferred gain and issuance costs, net, reflected the amortization of deferred gains, partially offset by the amortization and write-off of existing deferred issuance costs. The increase in equity attributable to common stock primarily reflected the net income for the period. Equity attributable to noncontrolling interest reflected contributions from BSP and its share of the net loss for the quarter ended March 31, 2017.

Statement of Operations Analysis

Pre-tax income increased by $180 million in the three months ended March 31, 2017 compared to the same period in 2016. This increase was driven by higher commodity prices and improved price differentials and derivatives results, partially offset by lower production and higher production costs. The following table presents the results of our operations:



	Three months ended March 31,
	2017			2016
	(in millions)
Oil and gas net sales	$	487		$	329
Net derivative gains (losses)	73			(25		)
Other revenue	30			18
Production costs	(211		)	(184		)
General and administrative expenses	(67		)	(67		)
Depreciation, depletion and amortization	(140		)	(147		)
Taxes other than on income	(33		)	(39		)
Exploration expense	(6		)	(5		)
Other expenses, net	(22		)	(23		)
Interest and debt expense, net	(84		)	(74		)
Net gains on early extinguishment of debt	4			89
Gains on asset divestitures	21			—
Income (loss) before income taxes	52			(128		)
Income tax benefit	—			78
Net income (loss)	52			(50		)
Net (income) loss attributable to noncontrolling interest	1			—
Net income (loss) attributable to common stock	$	53		$	(50	)

Adjusted net loss	$	(43	)	$	(100	)
Adjusted EBITDAX^(a)	$	200		$	124

Effective tax rate	—		%	61		%

(a)

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

Our results of operations can include the effects of unusual and infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore, management uses measures called adjusted net income (loss) and adjusted general and administrative expenses, both of which exclude those items. These measures are not meant to disassociate items from management's performance, but rather are meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) and adjusted general and administrative expenses are not considered to be alternatives to net income (loss) or general and administrative expenses, respectively, reported in accordance with U.S. generally accepted accounting principles (GAAP).

The following table reconciles net income (loss) attributable to common stock to adjusted net income (loss) and presents net and adjusted net income (loss) per diluted share:



	Three months ended March 31,
	2017			2016
	(in millions)
Net income (loss) attributable to common stock	$	53		$	(50	)
Unusual and infrequent items:
Non-cash derivative (gains) losses	(75		)	81
Early retirement, severance and other costs	3			14
Net gains on early extinguishment of debt	(4		)	(89		)
Gains from asset divestitures	(21		)	—
Other	1			7
Adjusted income items before taxes	(96		)	13
Reversal of valuation allowance for deferred tax assets^(a)	—			(63		)
Total	(96		)	(50		)
Adjusted net loss	$	(43	)	$	(100	)

Net income (loss) attributable to common stock per diluted share	$	1.22		$	(1.30	)
Adjusted net loss per diluted share	$	(1.02	)	$	(2.60	)

(a) Amount represents the out-of-period portion of the valuation allowance reversal.

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



	Three months ended March 31,
	2017			2016
	(in millions)
Net income (loss) attributable to common stock	$	53		$	(50	)
Interest and debt expense, net	84			74
Income tax benefit	—			(78		)
Depreciation, depletion and amortization	140			147
Exploration expense	6			5
Adjusted income items before taxes	(96		)	13
Other non-cash items	13			13
Adjusted EBITDAX	$	200		$	124

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



	Three months ended March 31,
	2017			2016
	(in millions)
Non-cash derivative (gains) losses, excluding noncontrolling interest	$	(75	)	$	81
Non-cash derivative losses for noncontrolling interest	1			—
Cash payments (proceeds) from settled derivatives	1			(56		)
Net derivative (gains) losses	$	(73	)	$	25

The following table presents the reconciliation of our company-wide general and administrative expenses to adjusted general and administrative expenses:



	Three months ended March 31,
	2017			2016
	(in millions)
General and administrative expenses	$	67		$	67
Early retirement and severance costs	(3		)	(14		)
Adjusted general and administrative expenses	$	64		$	53

The following represents key metrics of our oil and gas operations, excluding certain corporate items, on a per Boe basis:



	Three months ended March 31,
	2017		2016
Production costs	$	17.70	$	13.69
General and administrative expenses, as adjusted^(a)	$	0.76	$	0.76
Depreciation, depletion and amortization	$	11.07	$	10.38
Taxes other than on income	$	2.27	$	2.65


(a)	For 2017 and 2016, the amount excludes unusual and infrequent charges related to early retirement and severance costs associated with field personnel totaling $0.25 per Boe and $0.22 per Boe, respectively.

Three months ended March 31, 2017 vs. 2016

Oil and gas net sales increased 48%, or $158 million, for the three months ended March 31, 2017, compared to the same period of 2016, due to increases of approximately $180 million, $28 million and $15 million from higher oil, NGL and natural gas realized prices, respectively, partially offset by the effects of lower oil, NGL and natural gas production of $58 million, $3 million and $4 million, respectively. The higher realized oil prices reflected a significant increase in global oil prices and improved differentials. Our realized oil prices also included a cash payment of $1 million and cash proceeds of $56 million from our hedging program in 2017 and 2016, respectively. Daily oil and gas production volumes averaged 132,000 Boe in the first quarter of 2017, compared with 148,000 Boe in the first quarter of 2016, representing a year-over-year decline rate just under 11%, at the low end of our estimated overall annual base decline rate. The 2017 production was negatively impacted by 2,000 Boe per day due to the PSCs governing our Long Beach operations. Excluding this PSC effect, our year-over-year production decline would have been 9%. Average oil production decreased by 12%, or 12,000 barrels per day (10% excluding the PSC effect), to 86,000 barrels per day in the three months ended March 31, 2017, compared to the same period of the prior year. NGL production decreased by 6% to 16,000 barrels per day. Natural gas production decreased by 8% to 181 MMcf per day, reflecting lower declines as a result of workover activity in the Sacramento basin.

Net derivative gains were $73 million for the three months ended March 31, 2017, compared to a loss of $25 million in the comparable period of 2016, representing an overall change of $98 million. The 2017 amount included a non-cash derivative gain compared to a loss in the prior year, representing a $155 million change, partially offset by lower gains from cash settlements of $57 million. The non-cash change reflected changes in the commodity price curves during each of the respective periods.

Other revenue increased 67%, or $12 million, for the three months ended March 31, 2017, compared to the same period of 2016. The increase reflected third-party power sales from our Elk Hills power plant which was offline for about half of the first quarter of 2016 for a planned turnaround.

Production costs for the three months ended March 31, 2017 increased $27 million, to $211 million or $17.70 per Boe, compared to $184 million or $13.69 per Boe for the same period of 2016, resulting in a 15% increase on an absolute dollar basis. The year-over-year increase was driven by higher gas prices used in steam and power generation and our ramp-up of activity in line with the stronger commodity prices. Total production costs in the first quarter of 2016 reflected management's decision to selectively defer workovers and downhole maintenance activity in light of low commodity prices. The first quarter of 2017 reflects normalized workover and downhole maintenance activity.

Our general and administrative expenses were comparable for the three months ended March 31, 2017 and the same period in the prior year. Our adjusted general and administrative expenses were $64 million and $53 million for the three months ended March 31, 2017 and 2016, respectively, each of which excluded early retirement and severance costs. The 2016 period reflected temporary employee benefit reductions. The 2017 period reflected higher performance-related bonus and incentive compensation largely due to better-than-expected performance. The non-cash portion of general and administrative expenses, comprising equity compensation and a portion of pension costs, was approximately $5 million and $7 million for the three months ended March 31, 2017 and 2016, respectively.

DD&A expense decreased 5%, or $7 million, for the three months ended March 31, 2017, compared to the same period of 2016. Of this decrease, approximately $16 million was attributable to lower volumes, partially offset by an increase in the DD&A rate of approximately $9 million.

Taxes other than on income, which include ad valorem taxes, greenhouse gas emissions costs and production taxes, decreased for the three months ended March 31, 2017, compared to the same period of 2016, largely due to lower property taxes.

Interest and debt expense, net, increased to $84 million for the three months ended March 31, 2017, compared to $74 million in the same period of 2016, due to higher blended interest rates in 2017 resulting from a $1 billion credit facility that we entered into in the third quarter of 2016, partially offset by the lower debt balances resulting from management's debt reduction actions throughout 2016.

Net gains on early extinguishment of debt consisted of the gains on debt repurchases for the three months ended March 31, 2017 and 2016.

Gains on asset divestitures consisted of $21 million of gains from non-core asset divestitures for the three months ended March 31, 2017.

Liquidity and Capital Resources

The primary source of liquidity and capital resources to fund our capital program and other obligations has been cash flow from operations. Operating cash flows are largely dependent on oil and natural gas prices, sales volumes and costs. Global oil prices improved beginning in the second quarter of 2016 through the first quarter of 2017. A meaningful, sustained drop in oil and natural gas prices from current levels could have a material adverse effect on our liquidity.

Much of the global exploration and production industry has been challenged at recent price levels, which put pressure on the industry's ability to generate positive cash flow and access capital. If commodity prices were to prevail through 2017 at about current levels, we would expect to be able to fund our operations and capital budget with our operating cash flows and would not anticipate a net draw down on our credit facilities. Our ability to borrow funds under the revolving portion of our first–lien, first-out credit facilities entered into in 2014 (2014 First–Out Credit Facilities) is limited by the size of our lenders' commitments, our ability to comply with covenants, our borrowing base and a minimum monthly liquidity requirement. Effective May 1, 2017, the borrowing base under the 2014 First–Out Credit Facilities was reaffirmed at $2.3 billion. Our credit limit under the 2014 First-Out Credit Facilities is $2.01 billion. As of March 31, 2017, we had approximately $500 million of available borrowing capacity under these facilities, subject to the minimum liquidity requirement.

If product prices currently projected in the forward price curves materialize, we expect to be in compliance with our covenants under the 2014 First–Out Credit Facilities through 2017 and possibly beyond. If we were to breach any of the covenants under the 2014 First–Out Credit Facilities, our lenders would be permitted to accelerate the principal amount due under such facilities and foreclose against the assets securing them. If payment were accelerated, or we failed to make certain payments, under these facilities, it would result in a default under our first-lien, second-out term loan credit facility (2016 Second-Out Credit Agreement) and outstanding notes and permit acceleration and foreclosure against the assets securing the 2016 Second-Out Credit Agreement and our secured notes. The lenders under the 2014 First-Out Credit Facilities have been supportive in granting amendments to facilitate our efforts to strengthen our balance sheet, including covenant amendments. However, we can make no assurances that they will continue to be.

The 2014 First–Out Credit Facilities mature at the earlier of November 2019 and the 182^nd day prior to the maturity of our 5% senior unsecured notes due January 15, 2020 (the 2020 notes) to the extent that more than $100 million of such notes remain outstanding at such date. The 2016 Second–Out Credit Agreement matures at the earlier of December 2021 and the 91^st day prior to maturity of the 2020 notes and 5 ½% senior unsecured notes due September 15, 2021 (2021 notes) if the outstanding principal amount of either series exceeds $100 million prior to its respective maturity date. As of March 31, 2017, we had $165 million and $135 million in aggregate principal amount of outstanding 2020 notes and 2021 notes, respectively.

We have a dynamic capital program that can be scaled up or down depending on the price environment. Our 2017 base capital budget was initially set at approximately $300 million. The two joint ventures that we recently entered into allow us to increase our total 2017 capital plan to a range of $400 million to $425 million, on a gross basis. For continued financial flexibility in a lower price environment, we expect to rely on internally generated cash flows from operations, settlements from our derivatives contracts, joint ventures, our available borrowing capacity and our ability to manage the pace of development activities.

We cannot guarantee our planned increase in investments will result in a rapid reversal of, or a significant increase in, production trends. Over the long term, if commodity prices fall again and remain at those depressed levels, we may experience continued declines in our production and reserves, which could reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations, the value of our assets and our borrowing base.

We focus on creating value and are committed to keeping our internally funded capital budget within our operating cash flows. Our low decline assets plus our high level of operational control give us the flexibility to adjust the level of our capital investments as circumstances warrant. We create dynamic budgets that can be adjusted to align investments with projected cash flows. We are also focusing our capital on oil projects, which provide higher margins and low decline rates that we believe will generate growing cash flow and fund increasing capital budgets to grow production assuming stable or increasing product pricing and modest service cost inflation. In this scenario, we expect to be able to strengthen our balance sheet organically.

We will continue to evaluate opportunities to strengthen our balance sheet to competitively position the company for the longer term. We expect our main source of deleveraging, as measured by a lower leverage ratio, will come from our future production growth through reinvesting substantially all of our operating cash flow into our business. However, we may also from time to time seek to further reduce our outstanding debt using cash from asset sales, other monetizations or other sources. Such activities, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our credit facilities, perceived credit risk by counterparties and other factors. The amounts involved may be material. We can give no assurances that any of these efforts will be successful.

Our strategy for protecting our cash flows and liquidity also includes our hedging program. We currently have the following Brent-based crude oil contracts, which includes activity subsequent to March 31, 2017:



	Q2 2017		Q3 2017		Q4 2017		Q1 2018		Q2 - Q4 2018		FY 2019		FY 2020
Crude Oil
Calls:
Barrels per day	5,600		5,600		10,600		16,200		15,500		500		400
Weighted-average price per barrel	$	55.60	$	57.54	$	56.83	$	58.81	$	58.87	$	60.00	$	60.00

Puts:
Barrels per day	20,600		17,600		10,600		600		500		500		400
Weighted-average price per barrel	$	50.24	$	50.85	$	48.11	$	50.00	$	50.00	$	50.00	$	50.00

Swaps:
Barrels per day	20,000		25,000		25,000		—		—		—		—
Weighted-average price per barrel	$	53.98	$	54.99	$	54.99	$	—	$	—	$	—	$	—

Credit Facilities

2014 First-Out Credit Facilities

The 2014 First-Out Credit Facilities comprise (i) a $609 million senior term loan facility (the Term Loan Facility) and (ii) a $1.4 billion senior revolving loan facility (the Revolving Credit Facility). We are permitted to increase the size of the Revolving Credit Facility by up to $250 million if we obtain additional commitments from new or existing lenders. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit. Our credit limit under the 2014 First-Out Credit Facilities is $2.01 billion. Borrowings under these facilities are also subject to a borrowing base, which was reaffirmed at $2.3 billion as of May 1, 2017.

As of March 31, 2017 and December 31, 2016, we had outstanding borrowings of $769 million and $847 million under our Revolving Credit Facility and $609 million and $650 million under the Term Loan Facility, respectively. In each of the quarters ended March 31, 2017 and 2016, we made a $25 million scheduled quarterly payment on the Term Loan Facility. Additionally, in February 2017, we made a $16 million Term Loan Facility prepayment from the proceeds of non-core asset sales.

We have granted the lenders under the 2014 First-Out Credit Facilities a first-priority lien in a substantial majority of our assets, including our Elk Hills power plant and midstream assets. We also granted a lien in the same assets to the lenders under the 2016 Second-Out Credit Agreement and the holders of our 8% senior secured second-lien notes due December 15, 2022 (2022 notes).

2016 Second-Out Credit Agreement

Senior Notes

In October 2014, we issued $5 billion in aggregate principal amount of our senior unsecured notes, including $1 billion of 2020 notes, $1.75 billion of 2021 notes and $2.25 billion of 6% senior unsecured notes due November 15, 2024 (2024 notes and collectively, the unsecured notes). We used the net proceeds from the issuance of the unsecured notes to make a $4.95 billion cash distribution to Occidental in October 2014.

In December 2015, we repurchased approximately $33 million in principal amount of the 2020 notes for $13 million in cash.

In 2016, we repurchased over $1.5 billion of our outstanding unsecured notes, primarily using drawings of $750 million on our Revolving Credit Facility and cash from operations. We also exchanged approximately 3.4 million shares of our common stock for unsecured notes in the aggregate principal amount of over $100 million.

Other

All obligations under the Credit Facilities and the notes are guaranteed both fully and unconditionally and jointly and severally by all of our material wholly owned subsidiaries. The assets and liabilities, results from operations and cash flows of our operating subsidiaries not guaranteeing the debt are de minimis. Our joint venture with BSP was funded in mid-March 2017 and is not a subsidiary guarantor.

The terms and conditions of all of our indebtedness are subject to additional qualifications and limitations that are set forth in the relevant governing documents.

At March 31, 2017, we were in compliance with all the financial and other covenants under our Credit Facilities.

A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on March 31, 2017 would result in a $3 million change in annual interest expense.

Cash Flow Analysis



	Three months ended March 31,
	2017			2016
	(in millions)
Net cash flows provided by operating activities	$	133		$	115
Net cash flows used by investing activities	$	—		$	(29	)
Net cash flows used by financing activities	$	(95	)	$	(88	)
Adjusted EBITDAX ^(a)	$	200		$	124

(a)

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

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



	Three months ended March 31,
	2017		2016
	(in millions)
Net cash provided by operating activities	$	133	$	115
Cash interest	44		48
Exploration expenditures	5		5
Other changes in operating assets and liabilities	17		(51		)
Other	1		7
Adjusted EBITDAX	$	200	$	124

Our net cash provided by operating activities for the three months ended March 31, 2017 increased by $18 million to $133 million from $115 million in the same period of 2016. The increase reflected higher revenues of approximately $113 million, primarily due to the net effect of higher commodity prices, lower volumes and lower derivative gains from cash settlements, as well as $6 million of lower taxes other than on income and lower interest payments of $4 million; partially offset by higher production costs of $27 million and higher cash general and administrative expenses of $11 million, as well as lower cash from working capital in the first quarter of 2017.

Our net cash flow used by investing activities of zero for the three months ended March 31, 2017 included approximately $50 million of capital investments offset by proceeds from asset divestitures of $33 million and changes in capital investment accruals of $17 million. Our net cash flow used by investing activities of $29 million for the three months ended March 31, 2016 primarily included $28 million of capital investments.

Our net cash flow used by financing activities of $95 million for the three months ended March 31, 2017 included approximately $78 million of net payments on the Revolving Credit Facility, $41 million of payments on the Term Loan Facility and $26 million of debt repurchases and transaction costs, partially offset by net contributions from our noncontrolling interest of $49 million. Our net cash flow provided by financing activities of $88 million for the three months ended March 31, 2016 primarily included approximately $44 million of net payments on the Revolving Credit Facility, $25 million of payments on the Term Loan Facility and debt repurchase and amendment costs of $20 million.

2017 Capital Program

We focus on creating value and are committed to maintain our internally funded capital budget within our operating cash flows. Our low decline assets plus our high level of operational control gives us the flexibility to adjust the level of such capital investments as circumstances warrant. We began 2017 with two rigs and had an average of three rigs for the quarter ended March 31, 2017. By the end of the year, we expect to be operating eight rigs, with two focused on steamfloods, two on shales, one on waterfloods and three on conventional reservoirs. We expect that one of the rigs will also be used for exploration in the second half of the year. We have developed a dynamic plan which can be scaled up or down depending on the price environment. Our 2017 base capital budget was initially set at approximately $300 million. The two joint ventures we entered into contemplate our partners providing capital for the development of certain of our oil and gas properties. As a result, we are increasing our total 2017 capital program to a range of $400 million to $425 million. The program will include up to $150 million in joint venture drilling and completions and internally funded amounts of $120 million for drilling and completions, $60 million for capital workovers, $50 million for facilities, $25 million primarily for mechanical integrity projects and $20 million for exploration. Our 2017 development program will focus on our core fields - Elk Hills, Wilmington, Kern Front, Buena Vista, Mt. Poso, Pleito Ranch, Wheeler Ridge and the delineation of Kettleman North Dome.

Lawsuits, Claims, Contingencies and Commitments

The previously disclosed purported class action against us relating to the Trust Indenture Act of 1939 was dismissed in April 2017.

Significant Accounting and Disclosure Changes

Safe Harbor Statement Regarding Outlook and Forward-Looking Information

The information in this document includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business prospects, budgets, drilling and workover program, maintenance capital requirements, production, costs, operations, reserves, hedging activities, transactions and capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect our results of operations and financial position appear in Part I, Item 1A, Risk Factors of the 2016 Form 10-K.

Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the effect of our debt on our financial flexibility; insufficient capital, including as a result of lender restrictions, lower-than-expected operating cash flow, unavailability of capital markets or inability to attract investors; equipment, service or labor price inflation or unavailability; inability to replace reserves; inability to timely obtain government permits and approvals; inability to monetize selected assets or enter into favorable joint ventures; restrictions and changes in restrictions imposed by regulations including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products; risks of drilling; unexpected geologic conditions; tax law changes; changes in business strategy; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; incorrect estimates of reserves and related future net cash flows; risks related to our disposition, joint venture and acquisition activities; the recoverability of resources; limitations on our ability to enter efficient hedging transactions; steeper than expected production decline rates; lower-than-expected production, reserves or resources from development projects or acquisitions; the effects of litigation; disruptions due to, insufficient insurance against and concentration of exposure in California to, accidents, mechanical failures, transportation constraints, labor difficulties, cyber attacks or other catastrophic events. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

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


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, 2017, there were no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A) - Quantitative and Qualitative Disclosures About Market Risk in the 2016 Form 10-K, except as discussed below.

Commodity Price Risk

As of March 31, 2017, we had a net derivative liability of $20 million carried at fair value, as determined from prices provided by external sources that are not actively quoted, which predominantly mature in 2017 and 2018. See additional hedging information in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources."

Credit Risk

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

As of March 31, 2017, the substantial majority of the credit exposures related to our business was with investment grade counterparties. We believe exposure to credit-related losses related to our business at March 31, 2017 was not material and losses associated with credit risk have been insignificant for all years presented.


Item 4.	Controls and Procedures

Our President and Chief Executive Officer and our Senior Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Senior Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2017.

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the first quarter of 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION


Item 1.	Legal Proceedings

For information regarding legal proceedings, see Note 7 to the consolidated condensed financial statements in Part I of this Form 10-Q and Part I, Item 3, "Legal Proceedings" in the Form 10-K for the year ended December 31, 2016.

The South Coast Air Quality Management District has issued notices of violation to a subsidiary of the company and its predecessor alleging that emissions at a facility in Huntington Beach, California exceeded permit conditions over certain periods in the past three years. The subsidiary is cooperating with the District to address the matter, which is expected to include monetary sanctions in excess of $100,000 but is not expected to be material to our financial statements.


Item 1.A.	Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading "Risk Factors" in our Form 10-K for the year ended December 31, 2016.


Item 5.	Other Disclosures

None.


Item 6.	Exhibits



	10.1	Sixth Amendment to Credit Agreement, dated as of February 14, 2017, among California Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer (incorporated by reference herein to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 16, 2017).

	12	Computation of Ratios of Earnings to Fixed Charges.

	31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

	101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* - Filed herewith.

SIGNATURES

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



	CALIFORNIA RESOURCES CORPORATION



DATE:	May 4, 2017	/s/ Roy Pineci
		Roy Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)

EXHIBIT INDEX

EXHIBITS



	10.1	Sixth Amendment to Credit Agreement, dated as of February 14, 2017, among California Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer (incorporated by reference herein to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 16, 2017).

	12	Computation of Ratios of Earnings to Fixed Charges.

	31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

	101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* - Filed herewith.