California Resources Corp - FORM 10-Q

Attached files

file	filename
EX-32.1 - CERTIFICATIONS OF CEO AND CFO - California Resources Corp	a2016q3exhibit321.htm
EX-31.2 - CERTIFICATION OF CFO - California Resources Corp	a2016q3exhibit312.htm
EX-31.1 - CERTIFICATION OF CEO - California Resources Corp	a2016q3exhibit311.htm
EX-12 - RATIO OF EARNINGS TO FIXED CHARGES - California Resources Corp	a2016q3exhibit12.htm
EX-10.6 - EXHIBIT 10.6 - California Resources Corp	a2016q3exhibit106.htm
EX-10.5 - EXHIBIT 10.5 - California Resources Corp	a2016q3exhibit105.htm
EX-10.4 - EXHIBIT 10.4 - California Resources Corp	a2016q3exhibit104.htm
EX-10.3 - EXHIBIT 10.3 - California Resources Corp	a2016q3exhibit103.htm

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 September 30, 2016

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

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 September 30, 2016	41,217,175

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	17
	General	17
	Business Environment and Industry Outlook	17
	Seasonality	18
	Operations	19
	Fixed and Variable Costs	19
	Financial and Operating Results	19
	Balance Sheet Analysis	23
	Statement of Operations Analysis	24
	Liquidity and Capital Resources	27
	Cash Flow Analysis	32
	2016 Capital Program	33
	Lawsuits, Claims, Contingencies and Commitments	34
	Significant Accounting and Disclosure Changes	34
	Safe Harbor Statement Regarding Outlook and Forward-Looking Information	35
Item 3	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4	Controls and Procedures	36

Part II

Item 1	Legal Proceedings	37
Item 1A	Risk Factors	37
Item 5	Other Disclosures	37
Item 6	Exhibits	37

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

As of September 30, 2016 and December 31, 2015

(in millions)



	September 30,			December 31,
	2016			2015

CURRENT ASSETS

Cash and cash equivalents	$	10		$	12
Trade receivables, net	202			200
Inventories	61			58
Other current assets	83			168
Total current assets	356			438

PROPERTY, PLANT AND EQUIPMENT	20,905			20,996
Accumulated depreciation, depletion and amortization	(14,952		)	(14,684		)
Total property, plant and equipment	5,953			6,312

OTHER ASSETS	23			303

TOTAL ASSETS	$	6,332		$	7,053



CURRENT LIABILITIES

Current maturities of long-term debt	$	74		$	100
Accounts payable	205			257
Accrued liabilities	379			222
Current income taxes	—			26
Total current liabilities	658			605

LONG-TERM DEBT - PRINCIPAL AMOUNT	5,173			6,043

DEFERRED GAIN AND ISSUANCE COSTS, NET	410			491

OTHER LONG-TERM LIABILITIES	584			830

EQUITY

Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at September 30, 2016 and December 31, 2015	—			—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (September 30, 2016 - 41,217,175 and December 31, 2015 - 38,818,048)	—			—
Additional paid-in capital	4,841			4,782
Accumulated deficit	(5,327		)	(5,683		)
Accumulated other comprehensive loss	(7		)	(15		)

Total equity	(493		)	(916		)

TOTAL LIABILITIES AND EQUITY	$	6,332		$	7,053

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 and nine months ended September 30, 2016 and 2015

(in millions, except per share amounts)



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
REVENUES AND OTHER
Oil and natural gas net sales	$	424		$	520		$	1,157		$	1,687
Net derivative (losses) gains	(14		)	68			(157		)	50
Other revenue	46			38			95			100
Total revenues and other	456			626			1,095			1,837

COSTS AND OTHER
Production costs	211			246			583			730
General and administrative expenses	58			129			186			290
Depreciation, depletion and amortization	137			253			422			757
Taxes other than on income	37			42			118			150
Exploration expense	3			5			13			29
Interest and debt expense, net	95			82			243			244
Other expenses, net	29			23			45			74
Total costs and other	570			780			1,610			2,274

Net gain on early extinguishment of debt	660			—			793			—

INCOME (LOSS) BEFORE INCOME TAXES	546			(154		)	278			(437		)
Income tax benefit	—			50			78			165
NET INCOME (LOSS)	$	546		$	(104	)	$	356		$	(272	)

Net income (loss) per share of common stock
Basic	$	13.45		$	(2.72	)	$	8.97		$	(7.10	)
Diluted	$	13.06		$	(2.72	)	$	8.79		$	(7.10	)

Dividends per common share	$	—		$	0.01		$	—		$	0.03

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 and nine months ended September 30, 2016 and 2015

(in millions)



	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016		2015
Net income (loss)	$	546	$	(104	)	$	356	$	(272	)
Other comprehensive income (loss) items:
Pension and postretirement losses ^(a)	—		(4		)	—		(7		)
Reclassification to income of realized losses on pension and postretirement ^(b)	2		6			8		11
Other comprehensive income (loss), net of tax	2		2			8		4
Comprehensive income (loss)	$	548	$	(102	)	$	364	$	(268	)


(a)	No associated tax for the three and nine months ended September 30, 2016. Net of tax of $3 million and $5 million for the three and nine months ended September 30, 2015. See Note 9, Retirement and Postretirement Benefit Plans, for additional information.


(b)	No associated tax for the three and nine months ended September 30, 2016. Net of tax of $(4) million and $(7) million for the three and nine months ended September 30, 2015, respectively. See Note 9, 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 nine months ended September 30, 2016 and 2015

(in millions)



	Nine months ended September 30,
	2016			2015
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	356		$	(272	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	422			757
Deferred income tax benefit	(78		)	(165		)
Net derivative losses (gains)	157			(50		)
Proceeds from settled derivatives	86			17
Net gain on early extinguishment of debt	(793		)	—
Deferred gain and issuance costs amortization	(53		)	—
Other non-cash (gains) losses in income, net	53			126
Dry hole expenses	—			9
Changes in operating assets and liabilities, net	(5		)	(10		)
Net cash provided by operating activities	145			412

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(45		)	(323		)
Changes in capital investment accruals	(5		)	(202		)
Asset divestitures	19			—
Acquisitions and other	—			(17		)
Net cash used by investing activities	(31		)	(542		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from revolving credit facility	1,761			1,345
Repayments of revolving credit facility	(1,728		)	(1,224		)
Issuance of term loan	990			—
Payments on long-term debt	(329		)	—
Debt repurchase and amendment costs	(814		)	—
Issuance of common stock	4			7
Cash dividends paid	—			(8		)
Net cash (used) provided by financing activities	(116		)	120
Decrease in cash and cash equivalents	(2		)	(10		)
Cash and cash equivalents—beginning of period	12			14
Cash and cash equivalents—end of period	$	10		$	4

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Condensed Financial Statements

September 30, 2016

NOTE 1 THE SPIN-OFF AND BASIS OF PRESENTATION

The Separation and Spin-off

We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of 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. Prior to November 30, 2014, all material existing assets, operations and liabilities of Occidental's California business were consolidated under us. 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, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

Basis of Presentation

In the opinion of our management, the accompanying financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our financial position as of September 30, 2016 and the statements of operations, comprehensive income, and cash flows for the three and nine months ended September 30, 2016 and 2015, as applicable. We have eliminated all of our significant intercompany transactions and accounts.

During the third quarter of 2016, we reclassified prior period gains on debt transactions, net of costs, from other (income) expenses, net, to net gain on early extinguishment of debt. Additionally, we reclassified the current portion of deferred taxes of $59 million as of December 31, 2015 from other current assets to other assets, in accordance with the retrospective application of recently issued accounting rules.

We have prepared this report pursuant to the rules and regulations of the United States 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, 2015.


NOTE 2	ACCOUNTING AND DISCLOSURE CHANGES

In August 2016, the Financial Accounting Standards Board (FASB) issued rules that modify how certain cash receipts and cash payments are presented and classified in the statement of cash flows. These rules are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, with earlier adoption permitted. We are currently evaluating the impact of these rules on our financial statements.

In June 2016, the FASB issued rules that change how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value. These rules are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of these rules on our financial statements.

In April 2016, the FASB issued rules requiring that entities recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, in March 2016, the FASB issued rules intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations and whether an entity reports revenue on a gross or net basis. These rules have the same effective date, generally in the first interim period of fiscal year 2018, as the related revenue standard issued in 2014. We are currently evaluating the impact of these rules on our financial statements.

In March 2016, the FASB simplified several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. These rules are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted. We early adopted these rules in the second quarter of 2016 with no material changes reflected in our financial statements.

In February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. These rules will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with earlier application permitted. We are currently evaluating the impact of these rules on our financial statements.

In January 2016, the FASB issued rules that modify how entities measure equity investments and present changes in the fair value of financial liabilities. Unless the investments qualify for a practicality exception, the new rules require all equity investments to be measured at fair value with changes in the fair value recognized through net income (other than those accounted for under the equity method of accounting or those that result in consolidation of the investee). Entities will have to record changes in instrument-specific credit risk for financial liabilities measured under the fair value option in other comprehensive income. These new rules become effective for fiscal years beginning after December 15, 2017 with no early adoption permitted. We are currently evaluating the impact of these rules, but we do not expect them to have a significant impact on our financial statements.


NOTE 3	OTHER INFORMATION

Other current assets at September 30, 2016 and December 31, 2015 included amounts due from joint interest partners, net, of approximately $36 million and $42 million and derivative assets from commodities contracts of $25 million and $88 million, respectively.

Other assets at December 31, 2015 included deferred tax assets of approximately $258 million (none at September 30, 2016).

Accrued liabilities reflected greenhouse gas obligations of $86 million and $6 million at September 30, 2016 and December 31, 2015, respectively; accrued interest of $67 million and $39 million at September 30, 2016 and December 31, 2015 and derivative liabilities from commodities contracts of $64 million at September 30, 2016 (none at December 31, 2015).

Other long-term liabilities included asset retirement obligations of $332 million and $343 million at September 30, 2016 and December 31, 2015, respectively.

Other revenue largely comprised sales of the portion of electricity generated by our power plant that is sold to third parties, and the related costs are included in other expenses. In the nine months ended September 30, 2016, other expenses also included a $31 million of gain from the sale of non-core assets.

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 United States federal and state income tax payments during the nine-month periods ended September 30, 2016 and 2015. Interest paid totaled approximately $244 million and $248 million for the nine months ended September 30, 2016 and 2015, respectively.

Reverse Stock Split

Our stockholders approved a reverse stock split at the Company's annual stockholders’ meeting on May 4, 2016. Following this approval, our board of directors authorized a reverse split using a ratio of one share of common stock for every ten shares then outstanding. The split occurred on May 31, 2016 with trading on a post-split basis commencing the following day. Share and per share amounts included in this report have been restated to reflect this reverse stock split.

The split proportionally decreased the number of authorized shares of common stock from 2.0 billion shares to 200 million shares and preferred stock from 200 million to 20 million shares. The compensation committee of our board approved proportionate adjustments to the number of shares outstanding and available for issuance under our stock-based compensation plans and to the exercise price, grant price or purchase price relating to any award under the plans, using the same reverse split ratio, pursuant to existing authority granted to the committee under the plans.

NOTE 4 INVENTORIES

Inventories as of September 30, 2016 and December 31, 2015, consisted of the following:



	September 30, 2016		December 31, 2015
	(in millions)
Materials and supplies	$	57	$	55
Finished goods	4		3
Total	$	61	$	58

NOTE 5 DEBT

Debt as of September 30, 2016 and December 31, 2015, consisted of the following:



	September 30, 2016			December 31, 2015
	(in millions)
2014 First Out Credit Facilities (Secured First Lien)
Revolving Credit Facility	$	772		$	739
Term Loan Facility	671			1,000
2016 Second Out Credit Agreement (Secured First Lien)	1,000			—
Senior Notes (Secured Second Lien)
8% Notes Due 2022	2,250			2,250
Senior Unsecured Notes
5% Notes Due 2020	193			433
5 ½% Notes Due 2021	149			829
6% Notes Due 2024	212			892
Total Debt - Principal Amount	5,247			6,143
Less Current Maturities of Long-Term Debt	(74		)	(100		)
Long-Term Debt - Principal Amount	$	5,173		$	6,043

At September 30, 2016, deferred gain and issuance costs were $410 million net, consisting of $507 million of deferred gains offset by $97 million of deferred issuance costs. The December 31, 2015 deferred gain and issuance costs were $491 million net, consisting of $560 million of deferred gains offset by $69 million of deferred issuance costs.

Credit Facilities

Our first lien, first out credit facility (2014 First Out Credit Facilities) comprises (i) a $671 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 facility matures at the earlier of November 2019 and the 182nd day prior to the maturity of our 5% senior unsecured notes due January 15, 2020 (the 2020 notes), to the extent more than $100 million of such notes remain outstanding at such date. As of September 30, 2016, we had $193 million in aggregate principal amount of outstanding 2020 notes. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit.

As of February 2016, we amended the 2014 First Out Credit Facilities to change certain of our financial and other covenants. We again amended this agreement in April 2016 to facilitate certain types of deleveraging transactions and in August 2016 to further change certain of our covenants, grant additional collateral to our lenders and permit the incurrence of debt under a new first-lien, second-out term loan credit facility (2016 Second Out Credit Agreement). Borrowings under the 2014 First Out Credit Facility are subject to a borrowing base that was reaffirmed at $2.3 billion as of November 2016. 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 2016 Second Out Credit Agreement and the holders of our senior second lien secured notes due in 2022.

As of September 30, 2016 and December 31, 2015, we had outstanding borrowings under our Revolving Credit Facility of $772 million and $739 million, respectively, and outstanding borrowings of $671 million and $1 billion under the Term Loan Facility, respectively. We made scheduled quarterly payments on the Term Loan Facility during the quarters ended March 31, 2016, June 30, 2016 and September 30, 2016, an $11 million prepayment from the proceeds of non-core asset sales in the quarter ended June 30, 2016 and a $250 million prepayment from proceeds of the 2016 Second Out Credit Agreement.

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 greatest of (i) the administrative agent’s prime rate, (ii) the one-month LIBOR rate plus 1.00% and (iii) the federal funds effective rate plus 0.50%), 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, as limited by the borrowing base, 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 priority, first out secured debt to trailing four quarter EBITDAX (the First-Lien First-Out Leverage Ratio) not exceed 3.50 to 1.00 at any quarter end through the quarter ending June 30, 2017 and 3.25 to 1.00 for the quarters ending 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 at any quarter end through the quarter ending December 31, 2017. Starting 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 new first-lien asset coverage ratio of 1.20 to 1.00 as of any June 30 and December 31 beginning December 31, 2016, which is consistent with a covenant included in the 2016 Second Out Credit Agreement described below.

Our 2014 First Out Credit Facilities require us to apply 100% of the proceeds from asset sales to repay loans outstanding under the 2014 First Out Credit Facilities, except that we are permitted to use up to 40% (or, if our leverage ratio is less than 4:00 to 1:00, 60%) of proceeds from non-borrowing base asset monetizations to repurchase our notes to the extent available at a significant minimum discount to par, as specified in the 2014 First Out Credit Facilities. The 2014 First Out Credit Facilities also permit us to incur up to an additional $50 million of non-credit-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 (i) paying dividends or making other distributions to common stockholders and (ii) making capital investments in excess of $125 million during 2016 or in excess of $200 million during 2017 with a carryover of unused 2016 amounts. The amount permitted to be invested can be increased dollar-for-dollar at any time after June 30, 2017 by the lesser of (a) $50 million and (b) the positive difference between (i) a measure of our liquidity as of June 30, 2017 and (ii) the sum of $500 million and net cash proceeds obtained from non-borrowing base asset dispositions.

Our borrowing base under the 2014 First Out Credit Facilities is redetermined each May 1 and November 1. The borrowing base will be 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.

Substantially all of the restrictions imposed by the February 2016 amendment to the 2014 First Out Credit Facilities, other than the requirement for semiannual borrowing base redeterminations, may terminate in the future if we are able to comply with the financial covenants as they existed prior to giving effect to the amendment.

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 term loans bear interest at a floating rate per annum equal to 10.375% plus LIBOR, subject to a 1.00% LIBOR floor, determined for the applicable interest period (or ABR rates in certain circumstances). 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.

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 our 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. The 2016 Second Out Credit Agreement matures on December 31, 2021, but if the aggregate principal amount outstanding of either our 2020 Notes or our 5½% senior unsecured notes due September 15, 2021 (the 2021 Notes) exceeds $100 million 91 days prior to their respective maturity dates, the maturity date of the term loans will accelerate to such prior 91st day. As of September 30, 2016, we had $193 million and $149 million in aggregate principal amount of outstanding 2020 notes and 2021 notes, respectively.

The 2016 Second Out Credit Agreement provides for customary covenants and events of default consistent with, or generally less restrictive than, the covenants in our 2014 First Out Credit Facilities, including limitations on additional indebtedness, liens, asset dispositions, investments, 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 beginning December 31, 2016, consistent with the 2014 First Out Credit Facilities.

All obligations under the 2014 First Out Credit Facilities and the 2016 Second Out Credit Agreement (Credit Facilities) are guaranteed jointly and severally by all of our material wholly owned subsidiaries. The assets and liabilities of subsidiaries not guaranteeing the debt are de minimis.

At September 30, 2016, we were in compliance with the financial and other covenants under our Credit Facilities.

Senior Notes

In October 2014, we issued $5.00 billion in aggregate principal amount of our senior unsecured notes, including $1.00 billion of 2020 notes, $1.75 billion of 2021 notes and $2.25 billion of 6% senior unsecured notes due November 15, 2024 (the 2024 notes and together with the 2020 notes and the 2021 notes, the unsecured notes). The unsecured notes were issued at par and are fully and unconditionally guaranteed on a senior unsecured basis by all of our material subsidiaries. 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 exchanged $534 million, $921 million and $1,358 million in aggregate principal amount of the 2020 notes, the 2021 notes, and the 2024 notes, respectively, for $2.25 billion in aggregate principal amount of newly issued 8% senior secured second lien notes due December 15, 2022 (the 2022 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. Additionally, we incurred approximately $28 million in third-party costs which were fully expensed in 2015. The second 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 our Credit Facilities.

During the three months ended March 31, 2016, we repurchased over $100 million in aggregate principal amount of the senior unsecured notes for under $13 million in cash. During the three months ended June 30, 2016, we entered into privately negotiated exchange agreements with a holder of our 6% Senior Notes due 2024 and our 5 ½% Senior Notes due 2021 to exchange a total of approximately 2.1 million shares of our common stock on a post-split basis for notes in the aggregate principal amount of $80 million.

In August 2016 we repurchased $197 million, $605 million and $613 million in aggregate principal amount of our 2020 notes, 2021 notes and 2024 notes, respectively, for $750 million, resulting in a $660 million pre-tax gain, net of related expenses. Additionally, we wrote off approximately $12 million of deferred costs related to the repurchased notes.

In October 2016, we entered into privately negotiated exchange agreements with certain holders of our 6% Senior Notes due 2024 and 5 1/2% Senior Notes due 2021 to exchange a total of 1.3 million shares of our common stock for notes in the aggregate principal amount of $23 million.

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 senior unsecured notes and the second lien secured 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. These covenants are subject to a number of important qualifications and limitations that are set forth in the indenture. 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 our second lien secured notes also restricts our ability to sell certain assets and to release collateral from liens securing the second lien secured notes, unless the collateral is released in compliance with our Credit Facilities.

Other

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 September 30, 2016 and December 31, 2015, including the fair value of the variable rate portion, was approximately $4.3 billion and $3.6 billion, respectively, compared to a carrying value of approximately $5.2 billion and $6.1 billion. A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on September 30, 2016, would result in a $3 million change in annual interest expense.

As of September 30, 2016 and December 31, 2015, we had letters of credit in the aggregate amount of approximately $127 million and $70 million (including $122 million and $49 million under the Revolving Credit Facility), respectively, which were issued to support ordinary course marketing, insurance, regulatory and other matters.

NOTE 6 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.

On April 21, 2016, a purported class action was filed against us in the United States District Court for the Southern District of New York on behalf of all beneficial owners of our unsecured notes from November 12, 2015 to the present. The complaint alleges that our December 2015 debt exchange excluded non-qualified institutional holders in violation of the Trust Indenture Act of 1939 and related law and, thereby, impaired their rights to receive principal and interest payments. The purported class action seeks declaratory relief that the debt exchange and the liens securing the new notes are null and void and that the debt exchange resulted in a default. The plaintiff also seeks monetary damages and attorneys’ fees. The Company plans to vigorously defend against the claims made by the plaintiff.

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. Reserves balances at September 30, 2016 and December 31, 2015 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 September 30, 2016, we are not aware of material indemnity claims pending or threatened against the Company.

We were contacted by the Internal Revenue Service for examination of our U.S. federal income tax return for the one month ended December 2014. Subsequent taxable years and state returns remain subject to examination.

NOTE 7 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 our credit facility covenants 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. We apply hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, we recognize any fair value gains or losses, over the remaining term of the hedge instrument, in earnings in the current period.

As of September 30, 2016, 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 and PG&E City Gate-based gas hedge positions as of September 30, 2016:



	Q4 2016		FY 2017		FY 2018
Crude Oil
Calls:
Barrels per day	25,000		20,500		21,500
Weighted-average price per barrel	$	53.62	$	53.11	$	58.21

Puts:
Barrels per day	3,000		14,300		—
Weighted-average price per barrel	$	50.00	$	48.60	$	—

Swaps:
Barrels per day	39,000		15,000		—
Weighted-average price per barrel	$	49.71	$	53.64	$	—

Gas
Swaps:
Millions British Thermal Units (MMBTU) per day	5,500		—		—
Weighted-average price per MMBTU	$	3.50	$	—	$	—

Forward Contracts:
MMBTU per day	—		6,200		—
Weighted-average price per MMBTU	$	—	$	3.53	$	—

Certain of our 2017 crude oil swaps grant our counterparty a quarterly option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46.

Subsequent to September 30, 2016, we acquired additional hedges bringing our total swaps on our 2017 oil production to 20,000 barrels per day with a weighted-average Brent price of $53.98. We also purchased derivative assets that partially reduced our call exposure on our 2017 production to a total of 15,500 barrels per day with a weighted-average Brent ceiling of $54.17. Additionally, we reduced our Q4 2016 natural gas swaps to 3,800 MMBTU per day at a weighted-average price of $3.49 and our 2017 natural gas forward contracts to 4,700 MMBTU per day at a weighted-average price of $3.53.

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 September 30, 2016 and December 31, 2015 (in millions):



	September 30, 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	$	56		$	(31	)	$	25
Commodity Contracts	Other assets	21			(15		)	6

Liabilities
Commodity Contracts	Accrued liabilities	(85		)	31			(54		)
Commodity Contracts	Other long-term liabilities	(89		)	15			(74		)
Total derivatives		$	(97	)	$	—		$	(97	)



	December 31, 2015
	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	$	87		$	—	$	87

Liabilities
Commodity Contracts	Accrued liabilities	(1		)	—		(1		)
Total derivatives		$	86		$	—	$	86

NOTE 8 EARNINGS PER SHARE

We compute earnings per share (EPS) using the two-class method required for participating securities. Undistributed earnings allocated to participating securities are subtracted from net income in determining net income attributable to common stockholders in any period that we issue dividends. Restricted and performance stock awards are considered participating securities because holders of such shares have non-forfeitable dividend rights in the event of our declaration of a dividend for common shares.

The denominator of basic EPS is the sum of the weighted-average number of common shares outstanding during the periods presented and vested stock awards that have not yet been issued as common stock; however, it excludes outstanding shares related to unvested stock awards. The denominator of diluted EPS is based on the basic shares outstanding, adjusted for the effect of unvested stock awards and outstanding option awards, to the extent they are dilutive, and participating securities. The effect of the stock options granted in August 2015 and December 2014 was anti-dilutive for the periods presented.

During the nine months ended September 30, 2016, we entered into privately negotiated exchange agreements with a holder of our 6% Senior Notes due 2024 and our 5 ½% Senior Notes due 2021 to exchange a total of approximately 2.1 million shares of our common stock on a post-split basis for notes in the aggregate principal amount of $80 million. In October 2016, we entered into privately negotiated exchange agreements with certain holders of our 6% Senior Notes due 2024 and 5 ½% Senior Notes due 2021 to exchange a total of 1.3 million shares of our common stock for notes in the aggregate principal amount of $23 million.

For the three and nine months ended September 30, 2016, we issued approximately 53,000 shares and 237,000 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- and nine-month periods ended September 30, 2016 and 2015:



	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016		2015
	(in millions, except per-share amounts)
Basic EPS calculation
Net income (loss)	$	546	$	(104	)	$	356	$	(272	)
Net income (loss) allocated to participating securities	—		—			—		—
Net income (loss) available to common stockholders	$	546	$	(104	)	$	356	$	(272	)

Weighted-average common shares outstanding - basic	40.6		38.3			39.7		38.3
Basic EPS	$	13.45	$	(2.72	)	$	8.97	$	(7.10	)

Diluted EPS calculation
Net income (loss)	$	546	$	(104	)	$	356	$	(272	)
Net income (loss) allocated to participating securities	—		—			—		—
Net loss available to common stockholders	$	546	$	(104	)	$	356	$	(272	)

Weighted-average common shares outstanding - basic	40.6		38.3			39.7		38.3
Dilutive effect of potentially dilutive securities	1.2		—			0.8		—
Weighted-average common shares outstanding - diluted	41.8		38.3			40.5		38.3
Diluted EPS	$	13.06	$	(2.72	)	$	8.79	$	(7.10	)

NOTE 9 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 September 30,
	2016					2015
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	—		$	1	$	1		$	1
Interest cost	1			1		1			1
Expected return on plan assets	(1		)	—		(1		)	—
Recognized actuarial loss	1			—		1			—
Settlement loss	1			—		10			10
Total	$	2		$	2	$	12		$	12



	Nine months ended September 30,
	2016					2015
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	1		$	3	$	3		$	3
Interest cost	2			3		3			3
Expected return on plan assets	(2		)	—		(3		)	—
Recognized actuarial loss	1			—		2			—
Settlement loss	6			—		18			10
Total	$	8		$	6	$	23		$	16

We contributed $1 million to our defined benefit pension plans during the three months ended September 30, 2016; however, no contributions were made during the same period of 2015. We contributed $7 million and $3 million to our defined benefit pension plans during the nine months ended September 30, 2016 and 2015, respectively. We expect to satisfy minimum funding requirements with contributions of $1 million to our defined benefit pension plans during the remainder of 2016. The 2016 and 2015 settlements were associated with early retirements.

NOTE 10 INCOME TAXES

For the nine months ended September 30, 2016, we had an income tax benefit of $78 million reflecting a change in the valuation allowance on our deferred tax assets. While we had pre-tax income of $278 million for the period, we had no income tax expense during the first nine months of 2016 because we expect a tax loss for 2016 for which no tax benefit has been recognized.


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

General

We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of 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. Prior to November 30, 2014, all material existing assets, operations and liabilities of Occidental's California business were consolidated under CRC. 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.

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.

In August 2016, we issued a new $1 billion first lien, second out term loan credit facility to prepay a portion of the existing term loans and revolving loans under our first lien, first out credit facility. Additionally, we tendered for and repurchased $1.4 billion in aggregate principal amount of our senior unsecured notes for $750 million using our existing revolver, resulting in a $660 million pre-tax gain, net of related expenses. This tender offer resulted in a net debt reduction of $625 million.

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 uncertainties. These and other factors make it impossible to predict realized prices reliably. Much of the global exploration and production industry is challenged at current price levels, putting pressure on the industry's ability to generate positive cash flow and access capital. Average oil prices continued the decline that began in the last half of 2014 into the first quarter of 2016. While global oil prices improved modestly through the third quarter of 2016 and started to trade in a narrower range, they were still lower in the three and nine months ended September 30, 2016 compared to the same periods in 2015.

Natural gas liquids (NGLs) prices have improved relative to crude oil prices over the last 12 months due to tighter supplies and higher contract prices on natural gasoline.

Natural gas prices remained lower in the three and nine months ended September 30, 2016 than comparable periods in 2015. However, prices rebounded strongly in the second half of the year due to lower production, higher demand and warmer weather. California natural gas differentials for the second half of the year also started to improve primarily due to reduced storage in the state.

The following table presents the average daily Brent, WTI and NYMEX prices for the three and nine months ended September 30, 2016 and 2015:



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Brent oil ($/Bbl)	$	46.98	$	51.17	$	43.01	$	56.61
WTI oil ($/Bbl)	$	44.94	$	46.43	$	41.33	$	51.00
NYMEX gas ($/Mcf)	$	2.70	$	2.78	$	2.24	$	2.86

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 significant producers and governments, actual or threatened production and refining disruptions, currency exchange rates, worldwide drilling and exploration activities, the effects of conservation, weather, geophysical and technical limitations, refining and processing disruptions, transportation bottlenecks and other matters affecting the supply and demand dynamics for oil, technological advances, regional market conditions, transportation capacity and costs in producing areas and 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 imports over 60% of its oil. A vast majority of the oil is imported via supertanker, with a negligible amount arriving by rail. 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 contributing to higher realizations than most other U.S. oil markets for comparable grades. Beginning in late 2015, the U.S. federal government allowed the export of crude oil. We are opportunistically pursuing newly opened 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 against the NYMEX index since we can deliver our gas for much 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 lower impact on our operating results.

Higher natural gas prices have a net positive effect on our operating results. In addition to selling natural gas, we also use gas for our steamfloods and power generation. As a result, any positive impact of higher prices is partially offset by higher operating costs. 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 provide part of the electricity output from our Elk Hills power plant to reduce operating costs to Elk Hills and nearby fields and increase reliability.

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 our credit facility covenants. 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 the level of activity, continuing to improve efficiencies and cost savings and working with our suppliers and service providers to adjust the cost of goods and services to reflect current market pricing. The reductions in our capital program will negatively impact our production levels in the near term and sustained low-price periods 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.

Operations

We conduct our operations through fee interests, land 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 2.4 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 our operations, including gas plants, oil and gas gathering systems, a power plant and other related assets, 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 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, 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 September 30, 2016.

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 less than 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.

Financial and Operating Results

Third Quarter 2016 compared to Third Quarter 2015


•	Net income of $546 million reflected a net gain of $660 million on early extinguishment of debt.


•	Adjusted net loss decreased 17% from $86 million to $71 million.


•	Average daily oil and gas production volumes decreased 13% from 158,000 to 138,000 barrels of oil equivalent (Boe).


•	Realized crude oil prices, including the effect of cash received from settled hedges, decreased 10% from $47.79 to $43.03 per barrel.


•	Production costs decreased 14% from $246 million to $211 million.

First Nine Months of 2016 compared to First Nine Months of 2015


•	Net income of $356 million reflected a net gain of $793 million on early extinguishment of debt.


•	Adjusted net loss increased 4% from $234 million to $243 million.


•	Average daily oil and gas production volumes decreased 12% from 161,000 to 142,000 Boe.


•	Realized crude oil prices, including the effect of cash received from settled hedges, decreased 19% from $50.28 to $40.91 per barrel.


•	Production costs decreased 20% from $730 million to $583 million.

The table below reconciles net income (loss) to adjusted net loss and presents net and adjusted net loss per diluted share:



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	546		$	(104	)	$	356		$	(272	)
Non-cash, unusual and infrequent items:
Non-cash derivative losses (gains)	25			(53		)	243			(33		)
Severance and early retirement costs	1			62			19			72
Plant turnaround, outage and other costs	5			3			14			6
Net gain on early extinguishment of debt	(660		)	—			(793		)	—
Gain from asset divestitures	—			—			(31		)	—
Adjusted income items before interest and taxes	(629		)	12			(548		)	45
Deferred debt issuance costs write-off	12			—			12			—
Valuation allowance for deferred tax assets ^(a)	—			—			(63		)	—
Tax effects of these items	—			6			—			(7		)
Total	(617		)	18			(599		)	38
Adjusted net loss	$	(71	)	$	(86	)	$	(243	)	$	(234	)

Net income (loss) per diluted share	$	13.06		$	(2.72	)	$	8.79		$	(7.10	)
Adjusted net loss per diluted share	$	(1.75	)	$	(2.25	)	$	(6.12	)	$	(6.11	)

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

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



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Non-cash derivative losses (gains)	$	25		$	(53	)	$	243		$	(33	)
Proceeds from settled derivatives	(11		)	(15		)	(86		)	(17		)
Net derivative losses (gains)	$	14		$	(68	)	$	157		$	(50	)

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



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
General and administrative expenses	$	58		$	129		$	186		$	290
Severance and early retirement costs	(1		)	(62		)	(19		)	(72		)
Adjusted general and administrative expenses	$	57		$	67		$	167		$	218

Our results of operations can include the effects of non-cash, 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 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 loss and adjusted general and administrative expenses are not considered to be an alternative to net loss or general and administrative expenses, respectively, reported in accordance with United States generally accepted accounting principles (GAAP).

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



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Oil prices with hedge ($ per Bbl)	$	43.03	$	47.79	$	40.91	$	50.28

Oil prices without hedge ($ per Bbl)	$	41.73	$	46.10	$	37.54	$	49.70
NGLs prices ($ per Bbl)	$	22.45	$	16.92	$	20.36	$	19.64
Gas prices ($ per Mcf)	$	2.64	$	2.83	$	2.11	$	2.72

The following table presents our average realized prices as a percentage of Brent, WTI and NYMEX for the three- and six-month periods ended September 30, 2016 and 2015:



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Oil with hedge as a percentage of Brent	92	%	93	%	95	%	89	%

Oil without hedge as a percentage of Brent	89	%	90	%	87	%	88	%
Oil without hedge as a percentage of WTI	93	%	99	%	91	%	97	%
Gas with hedge as a percentage of NYMEX	98	%	102	%	94	%	95	%

The following table sets forth our average production volumes of oil, NGLs and natural gas per day for the three- and nine-month periods ended September 30, 2016 and 2015:



	Three months ended September 30,		Nine months ended September 30,
	2016	2015	2016	2015
Oil (MBbl/d)
San Joaquin Basin	56	64	58	65
Los Angeles Basin	29	32	30	33
Ventura Basin	5	7	5	7
Sacramento Basin	—	—	—	—
Total	90	103	93	105

NGLs (MBbl/d)
San Joaquin Basin	15	17	15	17
Los Angeles Basin	—	—	—	—
Ventura Basin	1	1	1	1
Sacramento Basin	—	—	—	—
Total	16	18	16	18

Natural gas (MMcf/d)
San Joaquin Basin	149	172	150	175
Los Angeles Basin	2	1	3	3
Ventura Basin	8	11	8	11
Sacramento Basin	34	42	36	45
Total	193	226	197	234

Total Production (MBoe/d)^(a)	138	158	142	161

_______________________


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 nine months ended September 30, 2016, the average prices of Brent oil and NYMEX natural gas were $43.01 per barrel and $2.24 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately 19 to 1.

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2015 to September 30, 2016 are discussed below:



	September 30, 2016		December 31, 2015
	(in millions)

Cash and cash equivalents	$	10	$	12
Trade receivables, net	$	202	$	200
Inventories	$	61	$	58
Other current assets	$	83	$	168
Property, plant and equipment, net	$	5,953	$	6,312
Other assets	$	23	$	303



Current maturities of long-term debt	$	74		$	100
Accounts payable	$	205		$	257
Accrued liabilities	$	379		$	222
Current income taxes	$	—		$	26
Long-term debt - principal amount	$	5,173		$	6,043
Deferred gain and issuance costs, net	$	410		$	491
Other long-term liabilities	$	584		$	830
Equity	$	(493	)	$	(916	)

See "Liquidity and Capital Resources" for further discussion of changes in our cash and cash equivalents and long-term debt, net.

The decrease in other current assets was mainly due to a reduction in the 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 mainly due to increased valuation allowances on deferred tax assets.

The decrease in current maturities of long-term debt was due to the prepayments on our existing term loan during 2016. The decrease in accounts payable reflected lower capital investments and production costs in 2016. The increase in accrued liabilities was primarily due to the deferral of gains related to sales of greenhouse gas allowances, the change in value of derivative liabilities and accrued interest on our debt, partially offset by the effect of severance and employee bonus payments during the first nine months of 2016. Current income taxes and other long-term liabilities as of December 31, 2015 included $336 million in tax liabilities that have subsequently been reclassified to deferred taxes. The other long-term liabilities also reflect higher derivative liabilities due to mark-to-market effects. The decrease in long-term debt reflected the retirement of a portion of our senior unsecured notes and the partial pay down of our bank credit facilities, partially offset by the incurrence of new term loans. The decrease in deferred gain and issuance costs, net, reflected the amortization of deferred gains and new deferred debt issuance costs, partially offset by the amortization and write-off of existing deferred issuance costs. The increase in equity primarily reflected the net income for the nine-month period in 2016.

Statement of Operations Analysis

The following table presents the results of our operations:



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Oil and gas net sales	$	424		$	520		$	1,157		$	1,687
Net derivative (losses) gains	(14		)	68			(157		)	50
Other revenue	46			38			95			100
Production costs	(211		)	(246		)	(583		)	(730		)
General and administrative expenses	(58		)	(129		)	(186		)	(290		)
Depreciation, depletion and amortization	(137		)	(253		)	(422		)	(757		)
Taxes other than on income	(37		)	(42		)	(118		)	(150		)
Exploration expense	(3		)	(5		)	(13		)	(29		)
Interest and debt expense, net	(95		)	(82		)	(243		)	(244		)
Other expenses, net	(29		)	(23		)	(45		)	(74		)
Net gain on early extinguishment of debt	660			—			793			—
Income tax benefit	—			50			78			165
Net income (loss)	$	546		$	(104	)	$	356		$	(272	)

Adjusted net income (loss)^(a)	$	(71	)	$	(86	)	$	(243	)	$	(234	)
Adjusted EBITDAX^(b)	$	164		$	212		$	448		$	680

Effective tax rate	—		%	32		%	(28		)%	38		%

________________________


(a)	See "Financial and Operating Results" above for our Non-GAAP reconciliation.

(b)

We define adjusted EBITDAX consistent with our first lien, 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 our 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.

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



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	546		$	(104	)	$	356		$	(272	)
Interest and debt expense	95			82			243			244
Income tax benefit	—			(50		)	(78		)	(165		)
Depreciation, depletion and amortization	137			253			422			757
Exploration expense	3			5			13			29
Adjusted income items before interest and taxes^(a)	(629		)	12			(548		)	45
Other non-cash items	12			14			40			42
Adjusted EBITDAX	$	164		$	212		$	448		$	680


(a)	See "Financial and Operating Results" for a table reconciling net income (loss) to adjusted net income (loss).

The following presents costs included in our oil and gas operations, excluding certain corporate items, on a per Boe basis for the three and nine months ended September 30:



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Production costs	$	16.63	$	16.91	$	15.01	$	16.56
General and administrative expenses	$	0.63	$	1.10	$	0.69	$	1.00
Depreciation, depletion and amortization	$	10.15	$	16.92	$	10.24	$	16.71
Taxes other than on income	$	2.44	$	2.50	$	2.63	$	3.02

Three months ended September 30, 2016 vs. 2015

Oil and gas net sales decreased 18%, or $96 million, for the three months ended September 30, 2016, compared to the same period of 2015, due to reductions of approximately $41 million and $50 million from lower oil prices and volumes, respectively; $3 million and $8 million from lower natural gas prices and volumes, respectively; and an increase of $9 million from higher NGL prices. The lower realized oil prices reflected a significant decrease in global oil prices. Our realized oil prices in 2016 and 2015 also included $11 million and $15 million of cash generated from our hedging program, respectively. Daily oil and gas production volumes averaged 138,000 Boe in the third quarter of 2016, compared with 158,000 Boe in the third quarter of 2015, representing a 13% year-over-year decline rate, consistent with our estimated overall annual base decline rate. The decrease includes PSC effects offset by production deferred from the second quarter of 2016 to the third quarter due to third-party pipeline disruptions. Average oil production decreased by 13%, or 13,000 barrels per day, to 90,000 barrels per day in the three months ended September 30, 2016, compared to the same period of the prior year. NGL production decreased by 11% to 16,000 barrels per day. Natural gas production decreased by 15% to 193 MMcf per day, consistent with our focus on liquids. The overall third-quarter production decline continued to reflect our decision to withhold development capital and selectively defer workover and downhole maintenance activity in the early part of the year. Due to the improved commodity price environment, we began increasing our activity levels gradually towards the end of the second quarter resulting in lower third-quarter decline rates on a quarter-over-quarter basis. The higher activity levels began contributing to production more meaningfully towards the end of the third quarter.

Derivative losses were $14 million for the three months ended September 30, 2016, compared to gains of $68 million in the comparable period of 2015. The change was largely due to volume and valuation changes in our outstanding derivative positions, partially offset by cash settlements.

Production costs for the three months ended September 30, 2016 decreased $35 million, to $211 million or $16.63 per Boe, compared to $246 million or $16.91 per Boe for the same period of 2015, resulting in a 14% decrease on an absolute dollar basis. The year-over-year decrease was driven by cost reductions across nearly all of our operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, which also reduced the cost of electricity. However, the increasing workover and downhole maintenance activity combined with higher gas and seasonal energy prices resulted in higher production costs for the third quarter 2016 compared to the prior-year quarter.

Our general and administrative expenses were lower for the three months ended September 30, 2016, compared to the same period of 2015, on a total dollar and per Boe basis, reflecting continued employee and contractor cost-reduction initiatives. The three months ended September 30, 2016 and 2015 included severance and early retirement costs of $1 million and $62 million, respectively. The non-cash portion of general and administrative expenses, comprising equity compensation and a portion of pension costs, was approximately $6 million and $7 million for the three months ended September 30, 2016 and 2015, respectively.

DD&A expense decreased 46%, or $116 million, for the three months ended September 30, 2016, compared to the same period of 2015. Of this decrease, approximately $98 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2015, and approximately $18 million was attributable to lower volumes.

Taxes other than on income, which include ad valorem taxes, greenhouse gas emissions costs and production taxes, decreased for the three months ended September 30, 2016, compared to the same period of 2015, largely reflecting lower property taxes assessed in the lower price environment.

Exploration expense decreased 40%, or $2 million, for the three months ended September 30, 2016, compared to the same period of 2015, primarily due to reduced exploration activity.

Interest and debt expense, net, increased to $95 million for the three months ended September 30, 2016, compared to $82 million in the same period of 2015, due to higher interest rates, increased amortization of deferred financing costs and a $12 million write-off of the deferred financing costs associated with the tender for our notes during the third quarter of 2016. The increases were partially offset by the amortization of the gain on our fourth quarter 2015 debt exchange and lower debt balances.

Net gain on early extinguishment of debt primarily consisted of the gains on the tender for our notes, net of related expenses.

For the three months ended September 30, 2016, while we had pre-tax income of $546 million, we had no income tax expense because we expect a tax loss for 2016 for which no tax benefit has been recognized during the three-month period. For the same period of 2015, we had a benefit of $50 million and a pre-tax loss of $154 million.

Nine months ended September 30, 2016 vs. 2015

Oil and gas net sales decreased 31%, or $530 million, for the nine months ended September 30, 2016, compared to the same period of 2015, due to reductions of approximately $346 million and $121 million from lower oil prices and volumes, respectively; $39 million and $20 million from lower natural gas prices and volumes, respectively; and $7 million from lower NGL volumes. The lower realized oil prices reflected a significant decrease in global oil prices. Our realized prices in 2016 and 2015 also included $86 million and $17 million of cash generated from our hedging program, respectively. Daily oil and gas production volumes averaged 142,000 Boe in the nine months ended September 30, 2016, compared with 161,000 Boe in the same period of 2015 representing a 12% year-over-year decline rate. Average oil production decreased by 11% or 12,000 barrels per day to 93,000 barrels per day in the first nine months ended September 30, 2016, compared to the same period of the prior year. NGL production decreased by 11% to 16,000 barrels per day. Natural gas production decreased by 16% to 197 MMcf per day, consistent with our focus on liquids.

Derivative losses were $157 million for the nine months ended September 30, 2016, compared to gains of $50 million in the comparable period of 2015. The change was largely due to volume and valuation changes in our outstanding derivative positions, partially offset by cash settlements.

Production costs for the nine months ended September 30, 2016 decreased by $147 million to $583 million or $15.01 per Boe, compared to $730 million or $16.56 per Boe for the same period of 2015, resulting in a 20% decrease on an absolute dollar basis. The decrease was driven by cost reductions across nearly all of our operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, as well as management's decision to increase economic thresholds for capital investment and selectively defer lower value workovers and downhole maintenance activity during the early part of the 2016.

Our general and administrative expenses were lower for the nine months ended September 30, 2016, compared to the same period of 2015, on a total dollar and per Boe basis, reflecting continued employee and contractor cost-reduction initiatives. The nine months ended September 30, 2016 and 2015 included severance and early retirement costs of $19 million and $72 million, respectively. The non-cash portion of general and administrative expenses, comprising equity compensation and a portion of pension costs, was approximately $20 million and $25 million for the nine months ended September 30, 2016 and 2015, respectively.

DD&A expense decreased 44%, or $335 million, for the nine months ended September 30, 2016, compared to the same period of 2015. Of this decrease, approximately $281 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2015, and approximately $54 million was attributable to lower volumes.

Taxes other than on income decreased for the nine months ended September 30, 2016, compared to the same period of 2015, reflected lower property taxes assessed in the lower price environment prevailing during the period.

Exploration expense decreased 55%, or $16 million, for the nine months ended September 30, 2016, compared to the same period of 2015, due to reduced exploration activity and lease rates.

Interest and debt expense, net, of $243 million for the nine months ended 2016, compared to $244 million in the same period of 2015, reflected the higher interest rates, increased amortization of deferred financing costs and a $12 million write-off of the deferred financing costs associated with the tender for our notes during the third quarter of 2016. Offsetting these effects were the amortization of the gain on our fourth quarter 2015 debt exchange and lower debt balances.

Other expenses for the nine months ended September 30, 2016 included the $31 million gain on non-core asset divestitures. Otherwise, the other expenses between the two periods were comparable.

Net gain on early extinguishment of debt for the nine months ended September 30, 2016 resulted from the tender for our notes as well as other note retirements, net of related expenses.

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. Average oil prices continued the decline that began in the last half of 2014 into the first quarter of 2016. While global oil prices improved modestly through the third quarter of 2016 and started to trade in a narrower range, they were still lower in the three and nine months ended September 30, 2016 compared to the same periods in 2015. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, and sustained low oil and natural gas prices could continue to have a material and adverse effect on our liquidity position.

Much of the global exploration and production industry is challenged at current price levels, putting pressure on the industry's ability to generate positive cash flow and access capital. If commodity prices were to prevail through the year at about current levels, we would not anticipate a draw down on our revolving credit facility for our annual cash needs, including our current capital program. Our ability to borrow under our revolving credit facility is limited by the size of the facility, by our ability to comply with its covenants, including quarterly financial covenants, and by our borrowing base. Effective November 1, 2016, the borrowing base under our existing first lien first out credit facility was reaffirmed at $2.3 billion. As of September 30, 2016, we had approximately $506 million of available borrowing capacity under our revolving credit facility.

If product prices increase at the rate currently projected in the forward strip and we maintain a cost structure similar to current levels, we expect to be able to comply with our senior bank credit facility covenants through the end of the first quarter of 2018 and possibly beyond. If we were to breach any of our covenants, our lenders would be permitted to accelerate or cross-accelerate the principal amount due under our credit facilities and foreclose on the assets securing them. If payment were accelerated under our credit facilities, it would result in a default under our outstanding notes and permit acceleration and foreclosure on the assets securing our secured notes.

At the beginning of the year, in response to commodity price declines, we budgeted $50 million for our 2016 capital program, compared to our 2015 capital investments of $401 million. In the first half of the year, we further reduced the pace of our capital program to below our initial budget. Since then and in response to recent commodity price improvements, we have modestly increased our planned 2016 capital investments to approximately $75 million to $80 million. Our slowdown of drilling activity from late 2015 through the first half of 2016, coupled with the selective deferral of expense and capital workover activity, led to a decline in production in 2016. However, we began increasing activity levels gradually towards the end of the second quarter, continuing into the third quarter. We started experiencing the positive impact of the increased activity towards the end of the third quarter, and expect to see further production benefit in the fourth quarter which should reduce the base production decline rate. We believe our overall annual base decline rate ranges from 10% to 15%. 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 or remain at 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 internally fund our capital budget with operating cash flows. Our low decline assets plus our high level of operational control and absence of significant long-term drilling commitments give us the flexibility to adjust the level of such capital investments as circumstances warrant. We create dynamic budgets that can be adjusted to align investments with projected cash flows. In the event of improved and more consistent prices and cash flow, we may choose to deploy additional capital based on our Value Creation Index (VCI) investment metric, while abiding by our financial covenants.

We have taken a number of other steps to better align our cost structure with the current price environment including a reduction of our workforce to below 1,500 employees as of September 2016. As a result of these steps, in 2016, we have seen a reduction in our production costs and general and administrative expense below 2015 levels. These measures have helped offset some of the cash flow effects of prolonged low commodity prices.

In January and February 2016, we repurchased over $100 million in aggregate principal amount of the senior unsecured notes for under $13 million in cash. In May 2016, we entered into privately negotiated exchange agreements with a holder of our 6% Senior Notes due 2024 and our 5 ½% Senior Notes due 2021 to exchange a total of approximately 2.1 million shares of our common stock on a post-split basis for notes in the aggregate principal amount of $80 million. In August 2016, we issued a new $1 billion first lien, second out term loan credit facility (2016 Second Out Credit Agreement) to prepay a portion of our existing term loans and reduce outstanding revolving loans under our first lien, first out credit facility (2014 First Out Credit Facilities). In October 2016, we entered into privately negotiated exchange agreements with certain holders of our 6% Senior Notes due 2024 and 5 1/2% Senior Notes due 2021 to exchange a total of 1.3 million shares of our common stock for notes in the aggregate principal amount of $23 million.

Given the state of the commodity markets, we will continue to evaluate opportunities to strengthen our balance sheet to competitively position the company for the longer term. As a result, we may from time to time seek to further reduce our outstanding debt using cash from asset sales or other monetizations, exchanging debt for other debt or equity securities or engaging in joint ventures and other activities. 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. However, we can give no assurances that any of these efforts will be successful or adequately strengthen our balance sheet.

Our strategy for protecting our cash flows and liquidity also includes our hedging program. We currently have the following Brent-based crude oil and PG&E City Gate-based gas hedges:



	Q4 2016		FY 2017		FY 2018
Crude Oil
Calls:
Barrels per day	25,000		15,500		21,500
Weighted-average price per barrel	$	53.62	$	54.17	$	58.21

Puts:
Barrels per day	3,000		14,300		—
Weighted-average price per barrel	$	50.00	$	48.60	$	—

Swaps:
Barrels per day	39,000		20,000		—
Weighted-average price per barrel	$	49.71	$	53.98	$	—

Gas
Swaps:
MMBTU per day	3,800		—		—
Weighted-average price per MMBTU	$	3.49	$	—	$	—

Forward Contracts:
MMBTU per day	—		4,700		—
Weighted-average price per MMBTU	$	—	$	3.53	$	—

Certain of our 2017 crude oil swaps grant our counterparty a quarterly option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46.

Credit Facilities

The 2014 First Out Credit Facilities comprise a (i) $671 million senior term loan facility (the Term Loan Facility) and (ii) $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 facility matures at the earlier of November 2019 and the 182nd day prior to the maturity of our 5% senior unsecured notes due January 15, 2020 (the 2020 notes), to the extent more than $100 million of such notes remain outstanding at such date. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit.

As of February 2016, we amended the 2014 First Out Credit Facilities to change certain of our financial and other covenants. We again amended this agreement in April 2016 to facilitate certain types of deleveraging transactions and in August 2016 to further change certain of our covenants, grant additional collateral to our lenders and permit the incurrence of debt under the 2016 Second Out Credit Agreement. Borrowings under the 2014 First Out Credit Facility are subject to a borrowing base that was reaffirmed at $2.3 billion as of November 1, 2016. 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 2016 Second Out Credit Agreement and the holders of our senior second lien secured notes due in 2022.

Our 2014 First Out Credit Facilities require us to apply 100% of the proceeds from asset sales to repay loans outstanding under the 2014 First Out Credit Facilities, except that we are permitted to use up to 40% (or, if our leverage ratio is less than 4:00 to 1:00, 60%) of proceeds from non-borrowing base asset monetizations to repurchase our notes to the extent available at a significant minimum discount to par, as specified in the 2014 First Out Credit Facilities. The 2014 First Out Credit Facilities also permit us to incur up to an additional $50 million, 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 (i) paying dividends or making other distributions to common stockholders and (ii) making capital investments in excess of $125 million during 2016 or in excess of $200 million during 2017 with a carryover of unused 2016 amounts. The amount permitted to be invested can be increased dollar-for-dollar at any time after June 30, 2017 by the lesser of (a) $50 million and (b) the positive difference between (i) a measure of our liquidity as of June 30, 2017 and (ii) the sum of $500 million and net cash proceeds obtained from non-borrowing base asset dispositions.

Substantially all of the restrictions imposed by the February 2016 amendment to the Credit Facilities, other than the requirement for semiannual borrowing base redeterminations, may terminate in the future if we are able to comply with the financial covenants as they existed prior to giving effect to the amendment.

At September 30, 2016, we were in compliance with the financial and other covenants under our Credit Facilities.

Senior Notes

In December 2015, we exchanged $534 million, $921 million and $1,358 million in aggregate principal amount of the 2020 notes, the 2021 notes, and the 2024 notes, respectively, for $2.25 billion in aggregate principal amount of newly issued 8% senior secured second lien notes due December 15, 2022 (the 2022 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. Additionally, we incurred approximately $28 million in third-party costs which were fully expensed in 2015. 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 our Credit Facilities.

In August 2016, we repurchased $197 million, $605 million and $613 million in aggregate principal amount of our 2020 notes, 2021 notes and 2024 notes, respectively, for $750 million using our Revolving Credit Facility, resulting in a $660 million pre-tax gain, net of related expenses. These repurchases resulted in a net reduction of our debt of $625 million. Additionally, we wrote off approximately $12 million of deferred costs related to the repurchased notes.

Other

A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on September 30, 2016, would result in a $3 million change in annual interest expense.

Cash Flow Analysis



	Nine months ended September 30,
	2016			2015
	(in millions)
Net cash flows provided by operating activities	$	145		$	412
Net cash flows used in investing activities	$	(31	)	$	(542	)
Net cash flows (used) provided by financing activities	$	(116	)	$	120
Adjusted EBITDAX ^(a)	$	448		$	680

_______________________________

(a)

We define adjusted EBITDAX consistent with our first lien, 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 our 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.

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:



	Nine months ended September 30,
	2016		2015
	(in millions)
Net cash provided by operating activities	$	145	$	412
Cash interest	244		248
Exploration expenditures	13		20
Other changes in operating assets and liabilities	32		(6		)
Plant turnaround, outage and other costs	14		6
Adjusted EBITDAX	$	448	$	680

Our net cash provided by operating activities was $145 million and $412 million for the nine months ended September 30, 2016 and 2015, respectively. The first nine months of 2016, as compared with the same period in 2015, reflected lower revenues of $466 million, primarily due to lower commodity prices and volumes, net of cash

generated from our hedging program, partially offset by lower production costs of $147 million, the cash portion of general and administrative expenses of $46 million and taxes other than on income of $32 million as well as the negative effect of working capital changes.

Our net cash flow used by investing activities decreased $511 million for the nine months ended September 30, 2016, compared to the same period of 2015, primarily due to significantly lower capital investments and lower payments related to capital activity from prior periods.

Our net cash flow used by financing activities of $116 million for the nine months ended September 30, 2016 included approximately $33 million in net proceeds from the Revolving Credit Facility, $329 million in payments on the Term Loan Facility and $814 million in debt repurchases and other costs. Our net cash flow provided by financing activities of $120 million for the nine months ended September 30, 2015 included approximately $121 million in net proceeds on the Revolving Credit Facility.

2016 Capital Program

At the beginning of the year, we budgeted $50 million for our 2016 capital program, primarily to maintain the mechanical integrity of our facilities and systems and operate them safely. In the first half of the year, we further reduced the pace of our capital program to below our initial budget. Since then and in response to recent commodity price improvements, we have modestly increased our planned 2016 capital investments to approximately $75 million to $80 million. Our slowdown of drilling activity from late 2015 through the first half of 2016, coupled with the selective deferral of expense and capital workover activity, led to a decline in production in 2016. However, we began increasing activity levels gradually towards the end of the second quarter, continuing in to the third quarter. We started experiencing the positive impact of the increased capital activity towards the end of the third quarter, and expect to see further production benefit in the fourth quarter which should reduce the base production decline rate. We believe our overall annual base decline rate ranges from 10% to 15%. 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 or remain at 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 internally fund our capital budget with operating cash flows. Our low decline assets plus our high level of operational control and absence of significant long-term drilling commitments give us the flexibility to adjust the level of such capital investments as circumstances warrant. We create dynamic budgets that can be adjusted to align investments with projected cash flows. In the event of improved and more consistent prices and cash flow, we may choose to deploy additional capital based on our VCI investment metric, while abiding by our financial covenants.

Lawsuits, Claims, Contingencies and Commitments

On April 21, 2016, a purported class action was filed against us in the United States District Court for the Southern District of New York on behalf of all beneficial owners of our unsecured notes from November 12, 2015 to the present. The complaint alleges that our December 2015 debt exchange excluded non-qualified institutional holders in violation of the Trust Indenture Act of 1939 and related law and, thereby, impaired their rights to receive principal and interest payments. The purported class action seeks declaratory relief that the debt exchange and the liens securing the new notes are null and void and that the debt exchange resulted in a default. The plaintiff also seeks monetary damages and attorneys’ fees. We plan to vigorously defend against the claims made by the plaintiff.

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, projected production, projected costs, future operations, hedging activities, future transactions, planned 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 2015 Form 10-K.

Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency of our operating cash flow to fund planned capital expenditures; steeper than expected production decline rates; inability to implement our capital investment program; inability to replace reserves; inability to obtain government permits and approvals; inability to monetize selected assets; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; risks related to our disposition and acquisition activities; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; the recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; the effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the Spin-off and the agreements related thereto. 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 and nine months ended September 30, 2016, 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 2015 Form 10-K, except as discussed below.

Commodity Price Risk

As of September 30, 2016, we had derivative assets of $31 million and derivative liabilities of $128 million carried at fair value, as determined from prices provided by external sources that are not actively quoted, which mature in 2016 through 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 September 30, 2016, 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 September 30, 2016 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 September 30, 2016.

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 third quarter of 2016 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 6 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, 2015.


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, 2015.


Item 5.	Other Disclosures

None


Item 6.	Exhibits



	10.1	Fifth Amendment to Credit Agreement, dated August 12, 2016, among California Resources Corporation, as the Borrowers and JP Morgan Chase Bank, N.A., as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A., as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (incorporated by reference herein Exhibit 10.2 to the Registration’s Current Report on Form 8-K filed August 17, 2016).

	10.2	Credit Agreement, dated August 12, 2016, among California Resources Corporation, as the Borrower, the several Lenders from time to time parties thereto, Goldman Sachs Bank USA, as Lead Arranger and Bookrunner, and The Bank of New York Mellon Trust Company, N.A., as Administrative Agent and Collateral Agent (incorporated by reference herein Exhibit 10.1 to the Registration’s Current Report on Form 8-K filed August 17 2016).

	10.3*	Omnibus Amendment, dated September 12, 2016, among California Resources Corporation, the Guarantors party thereto, the Collateral Trustee and the other parity lien representatives party thereto.

	10.4*	Intercreditor Agreement, dated December 15, 2015 between JP Morgan Chase Bank, N.A., as Priority Lien Agent and The Bank of New York Mellon trust Company, N.A., as Second Lien Collateral Agent for the Second Lien Secured Parties.

	10.5*	Form of 2016 Nonstatutory Stock Option Award Terms and Conditions.

	10.6*	Form of Performance Incentive Award Terms and Conditions.

	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:	November 3, 2016	/s/ Roy Pineci
		Roy Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)

EXHIBIT INDEX

EXHIBITS



	10.1	Fifth Amendment to Credit Agreement, dated August 12, 2016, among California Resources Corporation, as the Borrowers and JP Morgan Chase Bank, N.A., as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A., as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (incorporated by reference herein Exhibit 10.2 to the Registration’s Current Report on Form 8-K filed August 17, 2016).

	10.2	Credit Agreement, dated August 12, 2016, among California Resources Corporation, as the Borrower, the several Lenders from time to time parties thereto, Goldman Sachs Bank USA, as Lead Arranger and Bookrunner, and The Bank of New York Mellon Trust Company, N.A., as Administrative Agent and Collateral Agent (incorporated by reference herein Exhibit 10.1 to the Registration’s Current Report on Form 8-K filed August 17 2016).

	10.3*	Omnibus Amendment, dated September 12, 2016, among California Resources Corporation, the Guarantors party thereto, the Collateral Trustee and the other parity lien representatives party thereto.

	10.4*	Intercreditor Agreement, dated December 15, 2015 between JP Morgan Chase Bank, N.A., as Priority Lien Agent and The Bank of New York Mellon trust Company, N.A., as Second Lien Collateral Agent for the Second Lien Secured Parties.

	10.5*	Form of 2016 Nonstatutory Stock Option Award Terms and Conditions.

	10.6*	Form of Performance Incentive Award Terms and Conditions.

	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.

California Resources Corp - FORM 10-Q - November 3, 2016

Attached files

California Resources Corp Reports