10-Q

10-Q 1 crc10q9302015.htm 10-Q 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

¨ 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)

n/a

(Registrant's former name, former address and former fiscal year, if changed since last report)

_____________________

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 "accelerated filer", "large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act):

Large Accelerated Filer ¨ Accelerated Filer ¨ Non-Accelerated Filer þ 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, 2015	387,837,645

California Resources Corporation and Subsidiaries

Table of Contents



				PAGE

Part I	Financial Information

	Item 1.	Financial Statements (unaudited)

		Consolidated Condensed Balance Sheets —
			September 30, 2015 and December 31, 2014	2

		Consolidated Condensed Statements of Operations —
			Three and nine months ended September 30, 2015 and 2014	3

		Consolidated Condensed Statements of Comprehensive Income —
			Three and nine months ended September 30, 2015 and 2014	4

		Consolidated Condensed Statements of Cash Flows —
			Nine months ended September 30, 2015 and 2014	5

		Notes to Consolidated Condensed Financial Statements		6

	Item 2.	Management’s Discussion and Analysis of Financial
			Condition and Results of Operations	15

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29

	Item 4.	Controls and Procedures		30

Part II	Other Information

	Item 1.	Legal Proceedings		30

	Item 1A.	Risk Factors		31

	Item 5.	Other Disclosures		31

	Item 6.	Exhibits		31

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

(in millions)





	September 30,			December 31,
	2015			2014

CURRENT ASSETS

Cash and cash equivalents	$	4		$	14
Trade receivables, net	217			308
Inventories	73			71
Other current assets	308			308
Total current assets	602			701

PROPERTY, PLANT AND EQUIPMENT	20,845			20,536
Accumulated depreciation, depletion and amortization	(9,588		)	(8,851		)
	11,257			11,685

OTHER ASSETS	54			43

TOTAL ASSETS	$	11,913		$	12,429



CURRENT LIABILITIES

Current maturities of long-term debt	$	75		$	—
Accounts payable	280			588
Accrued liabilities	393			334
Total current liabilities	748			922

LONG-TERM DEBT, NET	6,345			6,292

DEFERRED INCOME TAXES	1,886			2,055

OTHER LONG-TERM LIABILITIES	579			549

EQUITY

Preferred stock (200 million shares authorized at $0.01 par value) no shares outstanding at September 30, 2015 and December 31, 2014	—			—
Common stock (2.0 billion shares authorized at $0.01 par value) outstanding shares (September 30, 2015 - 387,837,645 and December 31, 2014 - 385,639,582)	4			4
Additional paid-in capital	4,772			4,748
Accumulated deficit	(2,401		)	(2,117		)
Accumulated other comprehensive income / (loss)	(20		)	(24		)

Total equity	2,355			2,611

TOTAL LIABILITIES AND EQUITY	$	11,913		$	12,429

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, 2015 and 2014

(in millions)



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
REVENUES
Oil and natural gas net sales to third parties	$	596		$	630		$	1,754		$	678
Oil and natural gas net sales to related parties	—			421			—			2,560
Other revenue	30			41			83			115
	626			1,092			1,837			3,353
COSTS AND OTHER DEDUCTIONS
Production costs	246			271			730			805
General and administrative expenses	129			78			290			218
Depreciation, depletion and amortization	253			304			757			886
Taxes other than on income	42			56			150			163
Exploration expense	5			25			29			71
Interest and debt expense, net	82			—			244			—
Other expenses	23			39			74			109
	780			773			2,274			2,252

INCOME / (LOSS) BEFORE INCOME TAXES	(154		)	319			(437		)	1,101
Income tax (expense) / benefit	50			(131		)	165			(444		)
NET INCOME / (LOSS)	$	(104	)	$	188		$	(272	)	$	657

Net income / (loss) per share of common stock
Basic	$	(0.27	)	$	0.48		$	(0.71	)	$	1.69
Diluted	$	(0.27	)	$	0.48		$	(0.71	)	$	1.69

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, 2015 and 2014

(in millions)



	Three months ended September 30,					Nine months ended September 30,
	2015			2014		2015			2014
Net income / (loss)	$	(104	)	$	188	$	(272	)	$	657
Other comprehensive income / (loss) items:
Unrealized losses on derivatives ^(a)	—			—		—			(2		)
Pension and postretirement (losses) / gains ^(b)	(4		)	—		(7		)	1
Reclassification to income of realized losses on derivatives ^(c)	—			—		—			3
Reclassification to income of realized losses on pension and postretirement ^(d)	6			—		11			—
Other comprehensive income / (loss), net of tax	2			—		4			2
Comprehensive income / (loss)	$	(102	)	$	188	$	(268	)	$	659

(a) No tax for the three months ended September 30, 2015 and 2014. Net of tax of zero and $1 million for the nine months ended September 30, 2015 and 2014, respectively.

(b) Net of tax of $3 million and zero for the three months ended September 30, 2015 and 2014, respectively. Net of tax of $5 million and zero for the nine months ended September 30, 2015 and 2014, respectively. See Note 10, Retirement and Postretirement Benefit Plans, for additional information.

(c) No tax for the three months ended September 30, 2015 and 2014. Net of tax of zero and ($2) million for the nine months ended September 30, 2015 and 2014, respectively.

(d) Net of tax of ($4) million and zero for the three months ended September 30, 2015 and 2014, respectively. Net of tax of ($7) million and zero for the nine months ended September 30, 2015 and 2014, respectively. See Note 10, Retirement and Postretirement Benefit Plans, for additional information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Cash Flows

For the nine months ended September 30, 2015 and 2014

(in millions)



	2015			2014
CASH FLOW FROM OPERATING ACTIVITIES
Net income / (loss)	$	(272	)	$	657
Adjustments to reconcile net income / (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	757			886
Deferred income tax expense / (benefit)	(165		)	262
Other noncash charges to income	126			22
Dry hole expenses	9			52
Changes in operating assets and liabilities, net	(43		)	(12		)
Net cash provided by operating activities	412			1,867

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(323		)	(1,569		)
Changes in capital investment accruals	(202		)	24
Acquisitions and other	(17		)	(69		)
Net cash used by investing activities	(542		)	(1,614		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from revolving credit facility	1,345			—
Repayments of revolving credit facility	(1,224		)	—
Proceeds from issuance of common stock	7			—
Cash dividends paid	(8		)	—
Distributions to Occidental, net	—			(148		)
Net cash provided / (used) by financing activities	120			(148		)
Increase / (decrease) in cash and cash equivalents	(10		)	105
Cash and cash equivalents—beginning of period	14			—
Cash and cash equivalents—end of period	$	4		$	105

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, 2015

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 the 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 retained approximately 18.5% of our outstanding shares of common stock, which it has stated it intends to divest within 18 months of the Spin-off.

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

Basis of Presentation

Until the Spin-off, the accompanying financial statements were derived from the consolidated financial statements and accounting records of Occidental and were presented on a combined basis for the pre-Spin-off periods. These financial statements reflect the historical results of operations, financial position and cash flows of the California business. We account for our share of oil and gas exploration and production ventures, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets and statements of income and cash flows.

The statements of income for periods prior to the Spin-off included expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, treasury, tax, financial reporting, finance, internal audit, legal, risk management, information technology, government relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, marketing, ethics and compliance, and certain other shared services. These allocations were based primarily on specific identification of time or activities associated with us, employee headcount or our relative size compared to Occidental. Our management believes the assumptions underlying the financial statements, including the assumptions regarding allocating expenses from Occidental, are reasonable. However, the financial statements for the pre-Spin-off periods may not include all of the actual expenses that would have been incurred, may include duplicative costs and may not reflect our results of operations, financial position and cash flows had we operated as a stand-alone public company during the periods presented. Actual costs that would have been incurred if we had been a stand-alone company prior to the Spin-off would have depended on multiple factors, including organizational structure and strategic and operating decisions.

The assets and liabilities in the pre-Spin-off financial statements are presented on a historical cost basis. We have eliminated all of our significant intercompany transactions and accounts. Prior to the Spin-off, we participated in Occidental’s centralized treasury management program and had not incurred any debt. Excess cash generated by our business was distributed to Occidental, and likewise our cash needs were provided by Occidental, in the form of contributions.

All financial information presented after the Spin-off represents our financial position, results of operations and cash flows, as follows:


•	Our consolidated statements of operations, comprehensive income and cash flows for the three and nine months ended September 30, 2015, as applicable, consist of our stand-alone consolidated results following the Spin-off, and the three and nine months ended September 30, 2014 consist of the combined results of the California business.


•	Our consolidated balance sheets at September 30, 2015 and December 31, 2014 consist of our consolidated balances.

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, 2015, and the statements of operations, comprehensive income, and cash flows for the three and nine months ended September 30, 2015 and 2014, as applicable. The income / (loss) and cash flows for the periods ended September 30, 2015 and 2014 are not necessarily indicative of the income / (loss) or cash flows you should expect for the full year.

Certain prior year amounts have been reclassified to conform to the 2015 presentation. In the second quarter of 2015, we changed the classification of certain employee-related costs from general and administrative expenses to production costs to better align these costs with the functions performed by those employees. Prior period amounts have been changed to conform to the current year classification.

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. You should read this Form 10-Q 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, 2014.


NOTE 2	ACCOUNTING AND DISCLOSURE CHANGES

In July 2015, the Financial Accounting Standards Board (FASB) issued rules requiring entities to measure inventory within the scope of these rules at the lower of cost and net realizable value. These new rules will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, and must be applied prospectively with earlier application permitted. We do not expect these new rules to have a significant impact on our financial statements.

In May 2015, the FASB issued rules to remove the requirements to categorize within the fair value hierarchy all investments for which the fair value is measured using the net asset value (NAV) per share practical expedient. The new rules also limit disclosures to investments for which the entity has elected to measure the fair value using that practical expedient, rather than for all investments that are eligible to be measured at fair value using the NAV per share. These rules will be effective for annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption of the rules permitted. We do not expect the disclosure changes to have a significant impact on our financial statements.

In April 2015, the FASB issued rules to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of debt discounts. These rules will be effective for annual periods beginning after December 15, 2015 and interim periods within those fiscal years, with early adoption of the rules permitted for financial statements which have not been previously issued. We early adopted the new rule in the first quarter of 2015 and retrospectively reclassified unamortized debt issuance costs of $68 million at December 31, 2014. The amount was previously reflected in other assets.


NOTE 3	OTHER INFORMATION

Other current assets at September 30, 2015 and December 31, 2014, include amounts due from joint interest partners of approximately $110 million and $120 million, deferred tax assets of $55 million and $60 million, and greenhouse gas emission credits of $40 million and $65 million, respectively.

Accrued liabilities at September 30, 2015 and December 31, 2014, include accrued compensation-related costs of approximately $130 million and $95 million, interest payable of $65 million and $70 million and greenhouse gas liabilities of $75 million and $65 million, respectively. Of the $130 million accrued compensation-related costs at September 30, 2015, $40 million relates to third quarter voluntary retirement and employee reduction charges. Other long-term liabilities include asset retirement obligations of $397 million each at September 30, 2015 and December 31, 2014.

Other revenue and other expenses mainly comprise sales and the associated costs, respectively, of the portion of electricity generated by our power plant that is sold to third parties.

Supplemental Cash Flow Information

Prior to the Spin-off we did not make any United States federal and state income tax payments directly to taxing jurisdictions. During that period, our share of Occidental's tax payments or refunds were paid or received, as applicable, by our former parent. We did not make any United States federal or state income tax payments during the nine-month period ended September 30, 2015. Interest paid totaled approximately $248 million and zero for the nine months ended September 30, 2015 and 2014, respectively.

NOTE 4 INVENTORIES

Inventories as of September 30, 2015 and December 31, 2014, consisted of the following:



	2015		2014
	(in millions)
Materials and supplies	$	69	$	66
Finished goods	4		5
Total	$	73	$	71

NOTE 5 DEBT

Debt as of September 30, 2015 and December 31, 2014, consisted of the following:



	2015			2014
	(in millions)
Revolving Credit Facility	$	481		$	360
Term Loan Facility	1,000			1,000
5% notes due 2020	1,000			1,000
5 1/2% notes due 2021	1,750			1,750
6% notes due 2024	2,250			2,250

Total debt	6,481			6,360

Less: Current maturities of long-term debt	(75		)	—

Less: Deferred financing costs	(61		)	(68		)

Total long-term debt, net	$	6,345		$	6,292

Credit Facilities

We have a credit agreement with a syndicate of lenders that provides for (i) a five-year senior term loan facility (the Term Loan Facility) and (ii) a five-year senior revolving loan facility (the Revolving Credit Facility and, together with the Term Loan Facility, the Credit Facilities). All borrowings under these facilities are subject to certain customary conditions. During the third quarter of 2015, our corporate ratings from Moody's Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P) were downgraded to B1 and BB-, respectively, resulting in the imposition of a borrowing base and the requirement to grant security on a first-lien basis in our oil and gas reserves under our Credit Facilities. In addition, we amended the Credit Facilities effective as of November 2,

2015, to change certain of our financial and other covenants. The following describes the terms of our facilities after giving effect to this amendment.

The aggregate commitments of the lenders are $2.0 billion under the Revolving Credit Facility and $1.0 billion under Term Loan Facility, respectively. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit. We will be required to repay the Term Loan Facility in $25 million quarterly installments beginning on March 31, 2016. As of September 30, 2015, we had $481 million outstanding under our Revolving Credit Facility. Had the November 2, 2015 amendment been in place at September 30, 2015, we would have had borrowing availability of up to an additional $1,523 million, taking into account our cash balance at that time, subject to compliance with our quarterly financial covenants described below, which would have limited our ability to utilize the full amount.

Borrowings under the 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 on our borrowing base utilization or our most current leverage ratio and will vary from (a) in the case of LIBOR loans, 1.50% to 2.75% and (b) in the case of ABR loans, 0.50% to 1.75%. The unused portion of the Revolving Credit Facility is subject to a commitment fee equal to 0.50% per annum. We also pay customary fees and expenses under the 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.

All obligations under the Credit Facilities are guaranteed jointly and severally by all of our wholly-owned material subsidiaries. The assets and liabilities of subsidiaries not guaranteeing the debt are de minimis. Our ability to borrow under the Credit Facilities is subject to a borrowing base. Our initial borrowing base was set at $3.0 billion and is subject to redetermination on or around January 15, 2016, and thereafter will be redetermined annually by our lenders each May, commencing May 1, 2016. Between scheduled borrowing base redeterminations, we and the lenders (requiring a request from the lenders holding 66 2/3 percent of our commitments), may each request one special redetermination. We will be permitted to have security 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.

The Credit Facilities require us to apply 50% of the proceeds from certain transactions, including certain deleveraging transactions, to repay the Term Loan. We must also apply cash on hand in excess of $250 million to repay certain amounts outstanding under the Revolving Credit Facility. In addition, our ability to pay dividends or make other distributions to common stockholders is limited to $20 million per year. While we are subject to the borrowing base, the Credit Facilities require us to maintain the following financial covenants for the trailing twelve months ended as of the last day of each fiscal quarter: (a) a first lien senior secured leverage ratio of no more than 2.25 to 1.00 and (b) an interest expense ratio of no less than 2.00 to 1.00. At September 30, 2015, we were in compliance with the financial and other covenants under our Credit Facilities as they existed at that time. If we were to breach any of these covenants, our lenders would be permitted to accelerate the principal amount due under the facilities. If payment were accelerated it would result in a default under our notes described below.

Senior Notes

On October 1, 2014, we issued $5.00 billion in aggregate principal amount of our senior notes, including $1.00 billion of 5% senior notes due January 15, 2020 (the 2020 notes), $1.75 billion of 5 1/2% senior notes due September 15, 2021 (the 2021 notes) and $2.25 billion of 6% senior notes due November 15, 2024 (the 2024 notes and together with the 2020 notes and the 2021 notes, the notes). The 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 notes to make a $4.95 billion cash distribution to Occidental in October 2014.

We pay interest on the 2020 notes semi-annually in cash in arrears on January 15 and July 15 of each year, beginning on July 15, 2015. We pay interest on the 2021 notes semi-annually in cash in arrears on March 15 and September 15 of each year, beginning on March 15, 2015. We pay interest on the 2024 notes semi-annually in cash in arrears on May 15 and November 15 of each year, beginning on May 15, 2015.

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 coupled with a credit rating decline below investment grade, we will be required to offer to purchase the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest or to have exercised our redemption right.

We estimate the fair value of fixed-rate debt based on prices from known market transactions for our instruments. The estimated fair value of our debt at September 30, 2015 and December 31, 2014, the fixed rate portion of which was classified as Level 1, and the variable rate portion of which approximated fair value, was approximately $4.5 billion and $5.6 billion, respectively, compared to a net carrying value of approximately $6.4 billion and $6.3 billion, respectively. A one-eighth percent change in the variable interest rates on the borrowings under our Term Loan Facility and Revolving Credit Facility on September 30, 2015, would result in an approximately $2 million change in annual interest expense.

As of September 30, 2015 and December 31, 2014, we had letters of credit in the aggregate amount of approximately $23 million and $25 million, respectively, that were issued to support ordinary course marketing 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. We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at September 30, 2015 and December 31, 2014 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 the operation of our business while it was still owned by Occidental. As of September 30, 2015, we are not aware of circumstances that we believe would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

NOTE 7 DERIVATIVES

General

From time to time, we use a variety of derivative instruments intended to establish, as of the date of production, the price we receive, to improve the effective realized prices for oil and gas, and to protect our capital program in case of price deterioration. 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. We recognized approximately $53 million and $33 million of derivative gains from marking these contracts to market, which were included in net sales, for the three and nine months ended September 30, 2015, respectively.

As of September 30, 2015, our existing hedge positions, the initial values of which were not material, were as follows:


•	Weighted average Brent-based floors and ceilings of $61.25 per barrel and $73.88 per barrel, respectively, for 40,000 barrels per day of our fourth quarter 2015 oil production;


•	Brent-based hedges with a floor of $55 per barrel and a ceiling of $70 per barrel for 12,500 barrels per day of our January through June 2016 crude oil production;


•	Brent-based hedges with a floor of $50 per barrel and a weighted average ceiling of $74.42 per barrel for 3,000 barrels per day of our July through December 2016 oil production;


•	Index-based hedges at an average price of $3.01 per million British thermal units (MMBtu) for 40,000 MMBtu per day and weighted average floors and ceilings of $2.80 per MMBtu and $3.17 per MMBtu, respectively, for 20,000 MMBtu per day of our fourth quarter 2015 natural gas production. These same hedges were also in place for our third quarter 2015 natural gas production.

Subsequent to September 30, 2015, we entered into additional hedges for our first half 2016 crude oil production, bringing our first half 2016 hedging program to a total of 30,500 barrels per day with a weighted average floor of $52.38 per barrel and 35,500 barrels per day with a ceiling of $66.15 per barrel. The initial value of these hedges was not material.

For our third quarter 2015 oil production, we had hedged 70,000 barrels per day at weighted average Brent-based floors of $52.14 per barrel and 30,000 barrels per day at Brent-based ceilings of $72.12 per barrel. The initial value of these hedges was not material.

From January through June 2015 we had purchased options for 100,000 barrels of our crude oil production per day, at $50 per barrel Brent and sold options for 30,000 barrels per day for March through June 2015 at $75 per barrel Brent. The initial intrinsic and time values were deferred and subsequent changes were included in the net derivative losses reported in net sales. The initial intrinsic value, which was accounted for as a cash flow hedge, was insignificant.

Going forward, we will continue to be strategic and opportunistic in implementing any hedging program. Our objective is to protect against the cyclical nature of commodity prices to provide a level of certainty around our cash flows and margins necessary to implement our capital investment program and protect our ability to comply with our credit facility covenants.

For the first quarter of 2014 we had hedged 50 MMcf per day of our natural gas production, which qualified as cash-flow hedges. The weighted average strike price of these swaps was $4.30 per Mcf.

The after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (AOCI) for derivative instruments classified as cash-flow hedges for the three- and nine-month periods ended September 30, 2015 and 2014, and the ending AOCI balances at those dates were not material.

There were no fair value hedges as of and during the three- and nine-month periods ended September 30, 2015 and 2014.

Fair Value of Derivatives

Our commodity derivatives are measured at fair value with the changes recognized in the statement of operations using industry-standard models with various inputs, including quoted forward prices. The initial value of our 100,000 barrel put options from January through June 2015 was approximately $24 million on a gross and net basis, which approximated the time value of the instruments as of December 31, 2014.

The following table presents the gross and net fair values of our outstanding derivatives as of September 30, 2015 (in millions):



	Asset Derivatives			Liability Derivatives
September 30, 2015	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Other current assets	$	66	Accrued Liabilities	$	(4	)

Total gross and net fair value		$	66		$	(4	)

NOTE 8 FAIR VALUE MEASUREMENTS

We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 - using quoted prices in active markets for identical assets or liabilities; Level 2 - using observable inputs, such as quoted prices for similar assets and liabilities; and Level 3 - using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period.

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 (in millions):



	September 30, 2015
	Level 1		Level 2		Level 3		Collateral		Total
Assets:
Commodity derivative instruments, other current assets	$	—	$	66	$	—	$	—	$	66
Liabilities:
Commodity derivative instruments, accrued liabilities	$	—	$	4	$	—	$	—	$	4



	December 31, 2014
	Level 1		Level 2		Level 3		Collateral		Total
Assets:
Commodity derivative instruments, other current assets	$	—	$	24	$	—	$	—	$	24

Fair Values - Nonrecurring

During the nine months ended September 30, 2015 and 2014, we did not have any assets or liabilities measured at fair value on a non-recurring basis.

Financial Instruments Fair Value

The carrying amounts of cash and other on-balance sheet financial instruments, other than fixed-rate debt, approximate fair value.

NOTE 9 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. Restricted 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 daily 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 outstanding option awards, to the extent they are dilutive.

On the Spin-off date, we issued 381.4 million shares of our common stock. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed this amount to be outstanding as of the beginning of each period prior to the Spin-off presented in the calculation of weighted-average shares. In addition, we have assumed the vested stock awards granted in December 2014 were also outstanding for each of the periods presented prior to the Spin-off, resulting in a weighted-average basic share count of 381.8 million shares. The effect of stock options granted in December 2014 was anti-dilutive for the periods presented. For the three and nine months ended September 30, 2015, we issued approximately 792,000 shares and 1.5 million shares, respectively, of common stock in connection with our employee stock purchase plan. The effect of the employee stock purchase plan was anti-dilutive for the three and nine months ended September 30, 2015.

The following table presents the calculation of basic and diluted EPS for the three- and nine-month periods ended September 30, 2015 and 2014:



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(in millions, except per-share amounts)
Basic EPS calculation
Net income / (loss)	$	(104	)	$	188		$	(272	)	$	657
Net income / (loss) allocated to participating securities	—			(3		)	—			(11		)
Net income / (loss) available to common stockholders	$	(104	)	$	185		$	(272	)	$	646

Weighted-average common shares outstanding - basic	383.1			381.8			382.7			381.8
Basic EPS	$	(0.27	)	$	0.48		$	(0.71	)	$	1.69

Diluted EPS calculation
Net income / (loss)	$	(104	)	$	188		$	(272	)	$	657
Net income / (loss) allocated to participating securities	—			(3		)	—			(11		)
Net income / (loss) available to common stockholders	$	(104	)	$	185		$	(272	)	$	646

Weighted average common shares outstanding - basic	383.1			381.8			382.7			381.8
Dilutive effect of potentially dilutive securities	—			—			—			—
Weighted-average common shares outstanding - diluted	383.1			381.8			382.7			381.8
Diluted EPS	$	(0.27	)	$	0.48		$	(0.71	)	$	1.69

NOTE 10 RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans:



	Three months ended September 30,
		2015					2014
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	1		$	1	$	1		$	1
Interest cost		1			1		1			—
Expected return on plan assets		(1	)		—		(1	)		—
Recognized actuarial loss		1			—		—			1
Settlements / Curtailments		10			10		—			—
Total	$	12		$	12	$	1		$	2



	Nine months ended September 30,
		2015					2014
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	3		$	3	$	3		$	3
Interest cost		3			3		3			2
Expected return on plan assets		(3	)		—		(4	)		—
Recognized actuarial loss		2			—		1			1
Settlements / Curtailments		18			10		—			—
Total	$	23		$	16	$	3		$	6

We contributed $3 million to our defined benefit pension plans during the nine months ended September 30, 2015. We expect to contribute $10 million to our defined benefit pension plans in the fourth quarter of 2015. We did not make any contributions during the three-month period ended September 30, 2015, or either of the three- or nine-month periods ended September 30, 2014. The 2015 settlements / curtailments were associated with early retirements.

NOTE 11 RELATED-PARTY TRANSACTIONS

Through July 2014, substantially all of our products were sold to Occidental’s marketing subsidiaries at market prices and were settled at the time of sale to those entities. Beginning August 2014, we started marketing our own products directly to third parties. For the three and nine months ended September 30, 2014, related party sales included oil and natural gas products of approximately $421 million and $2,560 million, respectively, and power (reflected in other revenue) of approximately $25 million and $90 million, respectively.

Purchases from related parties reflect products purchased at market prices from Occidental’s subsidiaries prior to the Spin-off and used in our operations. These purchases were approximately $45 million and $165 million for the three and nine months ended September 30, 2014, respectively, and were included in production costs. There were no significant related-party receivable or payable balances at September 30, 2015 and December 31, 2014.

Prior to the Spin-off, the statement of operations included expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. Charges from Occidental for these services of approximately $43 million and $120 million for the three and nine months ended September 30, 2014, respectively, are reflected in general and administrative expenses.


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

Except when the context otherwise requires or where otherwise indicated, (1) all references to CRC, the Company, we, us and our refer to California Resources Corporation and its subsidiaries or the California business, (2) all references to the California business refer to Occidental’s California oil and gas exploration and production operations and related assets, liabilities and obligations, which we assumed in connection with our spin-off from Occidental on November 30, 2014 (the Spin-off), and (3) all references to Occidental refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries.

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 on April 23, 2014 and remained a wholly-owned subsidiary of Occidental until the Spin-off. 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. Occidental retained approximately 18.5% of our outstanding shares of common stock, which it has stated it intends to divest within 18 months of the Spin-off.

Basis of Presentation and Certain Factors Affecting Comparability

Until the Spin-off, the accompanying financial statements were derived from the consolidated financial statements and accounting records of Occidental and were presented on a combined basis for the pre-Spin-off periods. These financial statements reflect the historical results of operations, financial position and cash flows of the California business. All financial information presented after the Spin-off consists of the stand-alone consolidated results of operations, financial position and cash flows of CRC. We account for our share of oil and gas exploration and production ventures, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets and statements of income and cash flows.

The statements of income for periods prior to the Spin-off include expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, treasury, tax, financial reporting, finance, internal audit, legal, risk management, information technology, government relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, marketing, ethics and compliance, and certain other shared services. These allocations were based primarily on specific identification of time or activities associated with us, employee headcount or our relative size compared to Occidental. Our management believes the assumptions underlying the financial statements, including the assumptions regarding allocating expenses from Occidental, are reasonable. However, the financial statements for the pre-Spin-off periods may not include all of the actual expenses that would have been incurred, may include duplicative costs and may not reflect our results of operations, financial position and cash flows had we operated as a stand-alone public company during the periods presented. Actual costs that would have been incurred if we had been a stand-alone company prior to the Spin-off would have depended on multiple factors, including organizational structure and strategic and operating decisions.

Prior to the Spin-off, we participated in Occidental’s centralized treasury management program and did not incur any debt. Excess cash generated by our business was distributed to Occidental, and likewise our cash needs were provided by Occidental, in the form of contributions.

In the second quarter of 2015, we changed the classification of certain employee-related costs from general and administrative expenses to production costs to better align these costs with the functions performed by those employees. Prior period amounts have been changed to conform to the current year classification.

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. We respond to economic conditions by adjusting the size and allocation of our capital investments to be in line with those conditions, and continuing to pursue operating and capital efficiencies. The changes in our

capital program may have an impact on our future production levels and cash flows and sustained low-price periods may materially affect the quantities of oil and gas reserves we can economically produce.

During the course of 2015, we experienced significant and extended price declines as compared to prices for 2014, which will impact the quantity of reserves we report as of December 31, 2015. The unweighted arithmetic average first-day-of-the-month price for Brent decreased from $101.30 for 2014 to $55.89 for the first ten months of 2015. As a result, the SEC prices used to determine our December 31, 2015 fiscal year end reserves will likely be significantly lower than those used for December 31, 2014 and we will experience negative price related revisions to our proved reserves at December 31, 2015. Generally, lower prices adversely impact the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In addition, a portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the rules or may be removed due to a lower amount of capital available to develop these projects. However, our production-sharing contracts in Long Beach tend to partially offset these effects as our share of production and reserves from these contracts increases when prices decline. Further, during the course of the year we have implemented significant cost reduction and efficiency steps, which have reduced our operating costs by over 12% on a per BOE basis, and drilling costs by approximately 10% for shallow wells and up to 20% for deeper wells. These cost reductions would offset a portion of the loss of reserve quantities as some of the barrels that would become uneconomic in later years would remain economic, and we would be able to restore a portion of the proved undeveloped reserves that would otherwise be removed from the reserve quantities as more of them would become economic and we would expect to drill more wells with the same amount of capital. We expect further costs savings to be in effect by the end of the year, but cannot accurately estimate those savings as of this date. We do not currently have an estimate of our year-end 2015 reserve quantities. However, we have developed ranges of the potential impact of the low commodity prices on our reported reserves as of December 31, 2014. We believe that if we had determined our December 31, 2014 reserves using the SEC prices as calculated through October 1, 2015, including the estimated effect of known cost savings to date, our 2014 year-end reserves could have been reduced by approximately 10% to 20%. This estimate does not reflect the effect of further cost savings that we expect to implement by the end of the year, the effect of the 2015 production and the reserves that we expect to add as a result of our 2015 capital program, or any other adjustments or revisions to 2014 reserves. Subject to the completion of our year-end reserves estimates, we do not currently believe that prevailing commodity and the current strip prices would result in an impairment of the carrying value of our assets.

In the third quarter of 2015, we announced a voluntary retirement program and other employee actions to align our workforce with our view of a normalized commodity price environment. At the time of our spin-off, we had about 2,000 employees. We will end the year with about 1,700 employees, representing a 15% reduction mainly through attrition and the third quarter employee actions. We recorded a pre-tax charge of approximately $62 million in the third quarter of 2015 in connection with these actions. A significant majority of these costs will be paid to the affected employees over a period of eighteen months. We expect annual pre-tax savings of approximately $50 million, as a result of our third quarter actions, none of which is reflected in our third quarter results. We do not expect these actions to impact our production outlook; they will, however, starting in the fourth quarter of this year, reduce our operating costs and general and administrative expenses, as well as our drilling costs, and enhance our margins.

Given the recent volatile oil price environment, as well as our leverage, we began a hedging program shortly after the Spin-off to protect our capital investment program and our ability to comply with our credit facility covenants in case of further price deterioration. As of October 31, 2015, our existing hedge positions with respect to oil volumes were as follows:


•	Weighted average Brent-based floors and ceilings of $61.25 per barrel and $73.88 per barrel, respectively, for 40,000 barrels per day of our fourth quarter 2015 oil production;


•	Brent-based hedges with a weighted average floor of $52.38 per barrel and a ceiling of $66.15 per barrel for 30,500 barrels per day and 35,500 barrels per day, respectively, of our January through June 2016 crude oil production;


•	Brent-based hedges with a floor of $50 per barrel and a weighted average ceiling of $74.42 per barrel for 3,000 barrels per day of our July through December 2016 oil production.

The following graph represented our oil hedges as of October 31, 2015:

In addition, for our fourth quarter 2015 natural gas production we have index-based swaps at an average price of $3.01 per million British thermal units (MMBtu) for 40,000 MMBtu per day and weighted average floors and ceilings of $2.80 per MMBtu and $3.17 per MMBtu, respectively, for 20,000 MMBtu per day.

We will continue to be strategic and opportunistic with our hedging program in support of our capital investment plans.

We sell all of our crude oil into California markets. As a result we typically receive a premium associated with international waterborne-based prices because the structural energy deficit in the State results in most of its oil being imported. Over the last several years these prices have exceeded and continue to exceed West Texas Intermediate (WTI) based prices for comparable grades. Our realized crude oil prices in the third quarter of 2015 and for the nine months ended September 30, 2015 were lower than the comparable periods of 2014, reflecting a decline in the benchmarks as well as wider differentials, particularly in the first quarter of 2015, resulting from certain refinery interruptions. The differentials began improving in the second quarter and continued to improve in the third quarter of 2015 as the effects of these events have largely dissipated and have begun to approach historical norms.

The following table presents the average daily Brent, WTI and NYMEX prices for the three and nine months ended September 30, 2015 and 2014:



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Brent oil ($/Bbl)	$	51.17	$	103.39	$	56.61	$	107.02
WTI oil ($/Bbl)	$	46.43	$	97.17	$	51.00	$	99.61
NYMEX gas ($/MMBtu)	$	2.78	$	4.17	$	2.86	$	4.46

Oil prices and differentials will continue to be affected by (i) global supply and demand, which are generally a function of global economic conditions, the actions of OPEC, other significant producers and governments, inventory levels, threatened or actual production or refining disruptions, the effects of conservation, technological advances and regional market conditions; (ii) transportation capacity and cost in producing areas; (iii) currency exchange rates; and (iv) the effect of changes in these variables on market perceptions.

Prices and differentials for natural gas liquids (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 the pricing volatility of NGLs.

Natural gas prices and differentials are strongly affected by local supply and demand fundamentals, as well as availability of transportation capacity from producing areas.

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, and deliver dry gas to pipelines and sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. In addition, a portion of the power produced by our Elk Hills power plant is used for certain of our operations while a majority of the output is sold to third parties.

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 earnings 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 2.3 million net acres, approximately 60% of which we hold in fee. Our oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. We also own a network of strategically placed infrastructure assets which are integral to our underlying oil and natural gas production operations and are designed to maximize the value generated from our production, including gas plants, oil and gas gathering pipelines and systems, a power plant, compressors, steam generators, water separation and treatment facilities and other related assets.

Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts 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.

Fixed and Variable Costs

Our total production costs consist of variable costs that tend to vary depending on production levels, and fixed costs that 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 as they can be managed 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. If we see growth in a field we increase capacities, and similarly if a field is reaching the end of its economic life we would manage the costs while it remains economically viable to produce.

Financial and Operating Results

For the three and nine months ended September 30, 2015, we had a net loss of $104 million and $272 million, or ($0.27) and ($0.71) per diluted share, respectively, and an adjusted net loss of $86 million and $234 million, or ($0.22) and ($0.61) per diluted share. For the three and nine months ended September 30, 2014, both net income and adjusted net income were $188 million and $657 million, or $0.48 and $1.69 per diluted share, respectively. The table below reconciles net income / (loss) to adjusted net income / (loss):



	Three months ended September 30,					Nine months ended September 30,
	2015			2014		2015			2014
	(in millions)
Adjusted net income / (loss)	$	(86	)	$	188	$	(234	)	$	657
Early retirement and severance costs	(62		)	—		(72		)	—
Hedge related gains	53			—		33			—
Rig terminations and other costs	(3		)	—		(6		)	—
Tax-related adjustments	(6		)	—		7			—
Net income / (loss)	$	(104	)	$	188	$	(272	)	$	657

Our results of operations can include the effects of significant, unusual or infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income / (loss), which excludes those items. This measure is not meant to disassociate items from management's performance, but rather is meant to provide useful information to investors interested in comparing our earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income / (loss) is not considered to be an alternative to income / (loss) reported in accordance with United States generally accepted accounting principles (GAAP).

Adjusted results for the third quarter of 2015, compared to the same period in 2014, reflected higher oil volumes, and lower production costs, depreciation, depletion and amortization expense (DD&A), adjusted general and administrative expense, exploration expense and ad valorem tax expense, offset by significantly lower realized oil, NGL and gas prices and higher interest expense resulting from our current capital structure as an independent company. The third quarter 2015 net loss includes the effects of a pre-tax $62 million charge for the voluntary retirement program and employee reductions, non-cash hedge income of $53 million and other charges and tax related adjustments of $9 million.

Average oil production increased by 3% or 3,000 barrels per day to 103,000 barrels per day in the third quarter of 2015 compared to the same period of the prior year. NGL production decreased by 5% to 18,000 barrels per day and natural gas production decreased by 9% to 226 million cubic feet (MMcf) per day. Daily oil and gas production volumes averaged 158,000 barrels of oil equivalent (BOE) in the third quarter of 2015, compared with 160,000 BOE in the third quarter of 2014.

Realized crude oil prices decreased 50% to $47.79 per barrel including the effect of realized hedges in the third quarter of 2015 from $96.27 per barrel in the third quarter of 2014. The realized crude oil price in the current quarter before the effect of hedges was $46.10 per barrel. The decrease reflected the drop in global oil prices. Realized NGL prices decreased 64% to $16.92 per barrel in the third quarter of 2015 from $47.20 per barrel in the third quarter of 2014. Realized natural gas prices decreased 33% in the third quarter of 2015 to $2.83 per thousand cubic feet (Mcf), compared with $4.24 per Mcf in the same period of 2014.

The first nine months in 2015, compared to the same period in 2014, reflected higher volumes, in particular for oil, and lower production costs, DD&A, exploration expense and ad valorem tax expense, offset by significantly lower realized product prices in 2015 and higher interest expense. The net loss for the nine months ended September 30, 2015 includes the effects of pre-tax charges of $72 million for the voluntary retirement program and employee reductions mainly in the third quarter of 2015, non-cash hedge income of $33 million and other charges and the related tax effects of $1 million.

For the first nine months of 2015, daily oil and natural gas production averaged 161,000 BOE, compared with 157,000 in the first nine months of 2014. Average oil production increased 8,000 barrels per day, or by 8%, to 105,000 barrels per day in 2015. NGL production decreased by 5% to 18,000 barrels per day and natural gas production decreased by 5% to 234 MMcf per day.

Realized crude oil prices decreased 50% to $50.28 per barrel including the effect of realized hedges for the first nine months of 2015 from $100.94 per barrel for the first nine months of 2014. The realized crude oil price for the first nine months before the effect of hedges was $49.70 per barrel. The decrease reflected the drop in global oil prices. Realized NGL prices decreased 62% to $19.64 per barrel in the first nine months of 2015 from $52.26 per barrel for the first nine months of 2014. Realized natural gas prices decreased 40% to $2.72 per Mcf in the first nine months of 2015, compared with $4.53 per Mcf in the first nine months of 2014.

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, 2015 and 2014:



	Three months ended September 30,		Nine months ended September 30,
	2015	2014	2015	2014
Oil (MBbl/d)
San Joaquin Basin	64	65	65	63
Los Angeles Basin	32	29	33	28
Ventura Basin	7	6	7	6
Sacramento Basin	—	—	—	—
Total	103	100	105	97

NGLs (MBbl/d)
San Joaquin Basin	17	18	17	18
Los Angeles Basin	—	—	—	—
Ventura Basin	1	1	1	1
Sacramento Basin	—	—	—	—
Total	18	19	18	19

Natural gas (MMcf/d)
San Joaquin Basin	172	182	175	179
Los Angeles Basin	1	2	3	1
Ventura Basin	11	9	11	11
Sacramento Basin	42	56	45	55
Total	226	249	234	246

Total Production (MBoe/d)^(a)	158	160	161	157

_________________________


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, 2015, the average prices of Brent oil and NYMEX natural gas were $56.61 per barrel and $2.86 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately 20 to 1.

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



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Oil prices with hedge ($ per Bbl)	$	47.79	$	96.27	$	50.28	$	100.94
Oil prices without hedge ($ per Bbl)	$	46.10	$	96.27	$	49.70	$	100.94
NGLs prices ($ per Bbl)	$	16.92	$	47.20	$	19.64	$	52.26
Natural gas prices ($ per Mcf)	$	2.83	$	4.24	$	2.72	$	4.53

The following table presents our average realized prices as a percentage of Brent, WTI and NYMEX for the three- and nine-month periods ended September 30, 2015 and 2014:



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Oil with hedge as a percentage of Brent	93	%	93	%	89	%	94	%
Oil without hedge as a percentage of Brent	90	%	93	%	88	%	94	%
Oil with hedge as a percentage of WTI	103	%	99	%	99	%	101	%
Oil without hedge as a percentage of WTI	99	%	99	%	97	%	101	%
NYMEX gas	102	%	102	%	95	%	102	%

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2014 to September 30, 2015 are discussed below:



	September 30, 2015		December 31, 2014
	(in millions)

Cash and cash equivalents	$	4	$	14
Trade receivables, net	$	217	$	308
Inventories	$	73	$	71
Other current assets	$	308	$	308
Property, plant and equipment, net	$	11,257	$	11,685
Other assets	$	54	$	43



Current maturities of long-term debt	$	75	$	—
Accounts payable	$	280	$	588
Accrued liabilities	$	393	$	334
Long-term debt, net	$	6,345	$	6,292
Deferred income taxes	$	1,886	$	2,055
Other long-term liabilities	$	579	$	549
Equity	$	2,355	$	2,611

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

The decrease in trade receivables, net was mainly due to lower product prices for the third quarter of 2015, compared to the fourth quarter of 2014, and lower oil volumes. The decrease in property, plant and equipment reflected DD&A for the period, partially offset by capital investments.

The increase in current maturities of long-term debt reflected the 2016 quarterly payments due on the term loan facility. The decrease in accounts payable reflected the lower capital investments made in 2015. The increase in accrued liabilities was mainly due to the third quarter 2015 employee-related actions discussed earlier and higher

ad valorem tax accruals. The decrease in deferred income taxes was mainly due to our net loss for the first nine months of 2015, which resulted in net operating losses. The decrease in equity mainly reflected the net loss for the nine-month period in 2015.

Statement of Operations Analysis

The following table presents the results of our operations:



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(in millions)
Oil and gas net sales (including related parties)	$	596		$	1,051		$	1,754		$	3,238
Other revenue	30			41			83			115
Production costs	(246		)	(271		)	(730		)	(805		)
General and administrative expenses	(129		)	(78		)	(290		)	(218		)
Depreciation, depletion and amortization	(253		)	(304		)	(757		)	(886		)
Taxes other than on income	(42		)	(56		)	(150		)	(163		)
Exploration expense	(5		)	(25		)	(29		)	(71		)
Interest and debt expense, net	(82		)	—			(244		)	—
Other expenses	(23		)	(39		)	(74		)	(109		)
Income tax (expense) / benefit	50			(131		)	165			(444		)
Net income / (loss)	$	(104	)	$	188		$	(272	)	$	657

Adjusted net income / (loss)⁽¹⁾	$	(86	)	$	188		$	(234	)	$	657
Adjusted EBITDAX⁽²⁾	$	212		$	662		$	680		$	2,094

Effective tax rate	32		%	41		%	38		%	40		%

________________________


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

(2)

We define adjusted EBITDAX consistent with our credit facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and certain other non-cash items as well as unusual or infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry 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 certain of our financial covenants under our 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 a company’s financial performance, such as a company’s 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,
	2015			2014		2015			2014
	(in millions)
Net income / (loss)	$	(104	)	$	188	$	(272	)	$	657
Interest expense	82			—		244			—
Income tax expense / (benefit)	(50		)	131		(165		)	444
Depreciation, depletion and amortization	253			304		757			886
Exploration expense	5			25		29			71
Early retirement and severance costs	62			—		72			—
Hedge related gains	(53		)	—		(33		)	—
Rig terminations and other costs	3			—		6			—
Other, non-cash items	14			14		42			36
Adjusted EBITDAX	$	212		$	662	$	680		$	2,094

The following represents key metrics of 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,
	2015		2014		2015		2014
Production costs	$	16.91	$	18.35	$	16.56	$	18.78
Depreciation, depletion and amortization	$	16.92	$	20.21	$	16.71	$	20.31
Taxes other than on income	$	2.50	$	3.51	$	3.02	$	3.48

The following table presents the reconciliation of general and administrative expenses to adjusted general and administrative expenses (in millions):



	Three months ended September 30,					Nine months ended September 30,
	2015			2014		2015			2014
General and administrative expenses	$	129		$	78	$	290		$	218
Early retirement and severance costs	(62		)	—		(72		)	—
Adjusted general and administrative expenses	$	67		$	78	$	218		$	218

Three Months Ended September 30, 2015 vs. 2014

Oil and gas net sales decreased 43%, or $455 million, for the three months ended September 30, 2015, compared to the same period of 2014, mainly due to an approximately $455 million negative impact from lower oil prices, $50 million from lower NGL prices and $40 million from lower natural gas prices and volumes. The decrease was partially offset by an approximately $20 million positive impact from higher oil volumes, and a net gain of approximately $53 million from hedge related activity. Average oil production increased by 3% or 3,000 barrels per day to 103,000 barrels per day in the third quarter of 2015 compared to the same period of the prior year. NGL production decreased by 5% to 18,000 barrels per day and natural gas production decreased by 9% to 226 MMcf per day.

Other revenue decreased 27%, or $11 million, for the three months ended September 30, 2015, compared to the same period of 2014. The decrease reflected lower third-party power sales from our Elk Hills power plant, largely due to the lower rate structure set by California power utilities.

Production costs for the three months ended September 30, 2015 decreased $25 million, to $246 million or $16.91 per BOE, compared to $271 million or $18.35 per BOE for the same period of 2014, resulting in an 8% decrease on a per BOE basis. The decrease was driven by cost reductions across the board, particularly in well servicing efficiency, surface operations and energy use, and was also aided by lower natural gas and power prices.

Our adjusted G&A expense, which excludes the voluntary retirement and employee reduction costs, was lower for the three months ended September 30, 2015, compared to the same period of 2014, on a total dollar and per BOE basis, largely due to our cost reduction efforts and included lower stock-based compensation costs due to our lower quarter-end stock price. The non-cash portion of adjusted G&A comprising equity compensation and pension costs was approximately $7 million for the three months ended September 30, 2015.

DD&A expense decreased 17%, or $51 million, for the three months ended September 30, 2015, compared to the same period of 2014. Of this decrease, approximately $44 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2014, and approximately $7 million was attributable to lower volumes.

Taxes other than on income, which consist largely of ad valorem taxes, greenhouse gas credits and production taxes, for the three months ended September 30, 2015 decreased compared to the same period of 2014, largely reflecting lower ad valorem taxes.

Exploration expense decreased 80%, or $20 million, for the three months ended September 30, 2015, compared to the same period of 2014, consistent with our reduced exploration activity.

Interest and debt expense, net, of $82 million for the third quarter of 2015 was associated with the debt we incurred in connection with the Spin-off in the fourth quarter of 2014.

Other expenses decreased 41%, or $16 million, for the three months ended September 30, 2015, compared to the same period of 2014, reflecting lower natural gas costs for our Elk Hills power plant.

Income tax benefit of $50 million for the three months ended September 30, 2015 reflected a pre-tax loss of $154 million for the quarter, compared to an expense of $131 million in the same period of 2014, reflecting pre-tax income of $319 million. The change in the effective tax rate was due to a non-recurring spin-related income tax adjustment in the third quarter of 2015.

Nine Months Ended September 30, 2015 vs. 2014

Oil and gas net sales decreased 46%, or $1.5 billion, for the nine months ended September 30, 2015, compared to the same period of 2014, mainly due to approximately $1.4 billion negative impact from lower oil prices, $170 million from lower NGL prices and volumes, and $130 million from lower natural gas prices and volumes. The decrease was partially offset by an approximately $195 million positive impact from higher oil volumes, and a net gain of $33 million from hedge related activity. Average oil production increased 8,000 barrels per day, or by 8%, to 105,000 barrels per day in 2015. NGL production decreased by 5% to 18,000 barrels per day and natural gas production decreased by 5% to 234 MMcf per day.

Other revenue decreased 28%, or $32 million, for the nine months ended September 30, 2015, compared to the same period of 2014. The decrease reflected lower third-party power sales from our Elk Hills power plant, largely due to the lower rate structure set by California power utilities.

Production costs for the nine months ended September 30, 2015 decreased $75 million, to $730 million or $16.56 per BOE, compared to $805 million or $18.78 per BOE for the same period of 2014, resulting in a 12% decrease on a per BOE basis. The decrease was driven by cost reductions across the board, particularly in well servicing efficiency, surface operations and energy use, and was also aided by lower natural gas and power prices.

Our adjusted G&A expense, which excludes the voluntary retirement and employee reduction costs, was comparable for the nine months ended September 30, 2015, compared to the same period of 2014, on a total dollar and per BOE basis. The non-cash portion of adjusted G&A comprising equity compensation and pension costs was approximately $25 million for the nine months ended September 30, 2015.

DD&A expense decreased 15%, or $129 million, for the nine months ended September 30, 2015, compared to the same period of 2014. Of this decrease, approximately $150 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2014, partially offset by $15 million attributable to higher volumes.

Taxes other than on income for the nine months ended September 30, 2015 decreased compared to the same period of 2014, due to lower ad valorem taxes.

Exploration expense decreased 59%, or $42 million, for the nine months ended September 30, 2015, compared to the same period of 2014, consistent with our reduced exploration activity.

Interest and debt expense, net, of $244 million for the nine months ended September 30, 2015 was associated with the debt we incurred in connection with the Spin-off in the fourth quarter of 2014.

Other expenses decreased 32%, or $35 million, for the nine months ended September 30, 2015, compared to the same period of 2014, reflecting lower natural gas costs for our Elk Hills power plant.

Income tax benefit of $165 million for the nine months ended September 30, 2015 reflected a pre-tax loss of $437 million for the period, compared to an expense of $444 million in the same period of 2014, reflecting pre-tax income of $1,101 million. The change in the effective tax rate was due to a non-recurring spin-related income tax adjustment in the third quarter of 2015.

Liquidity and Capital Resources

The primary source of liquidity and capital resources to fund our capital program and other obligations is cash flow from operations. Through November 2014, any excess cash generated by our business was distributed to Occidental, and our cash needs were provided by Occidental, in the form of a contribution. We expect our needs for capital investments, other obligations and any dividends for at least the next twelve months will be met by cash generated from operations. Operating cash flows are largely dependent on oil and natural gas prices and differentials, sales volumes and costs. We plan to continuously evaluate our level of operating activity and capital as appropriate based on actual commodity prices. If the current conditions persist, we expect our future production levels may decrease modestly as we intend to continue to limit our capital program to a level consistent with our expected operating cash flows. We are pursuing certain transactions that may provide us with additional capital beyond our operating cash flows, which may mitigate the impact on our production. We are also pursuing a number of alternatives to deleverage our balance sheet and better align our capital structure for a more modest commodity price environment. Potential transactions may include a combination of asset monetizations, joint ventures and other deleveraging opportunities, such as capital market alternatives. The asset monetization opportunities we are pursuing primarily involve our midstream and power assets. Negotiations are ongoing and we are working toward definitive documentation. While we are working to announce at least one transaction this year, we cannot provide any assurance with respect to the terms or size of any transaction or that we will successfully complete these negotiations, execute definitive agreements by year end or ultimately close a transaction in the near term.

Our Board of Directors has decided to suspend the payment of our quarterly dividend of $0.01 per share, beginning immediately. This decision is consistent with the Company's broader initiatives to cut costs and reduce overall debt levels. In the longer term, our Board will re-evaluate the payment of dividends as commodity prices normalize.

Credit Facilities

We have a credit agreement with a syndicate of lenders that provides for (i) a five-year senior term loan facility (the Term Loan Facility) and (ii) a five-year senior revolving loan facility (the Revolving Credit Facility and, together with the Term Loan Facility, the Credit Facilities). All borrowings under these facilities are subject to certain customary conditions. During the third quarter of 2015, our corporate ratings from Moody's Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P) were downgraded to B1 and BB-, respectively, resulting in the imposition of a borrowing base and the requirement to grant security on a first-lien in our oil and gas reserves under our Credit Facilities. In addition, we amended the Credit Facilities effective as of November 2, 2015, to change certain of our financial and other covenants. The following describes the terms of our facilities after giving effect to this amendment.

$3.0 billion and is subject to redetermination on or around January 15, 2016 and thereafter will be redetermined annually by our lenders each May, commencing May 1, 2016. Between scheduled borrowing base redeterminations, we and the lenders (requiring a request from the lenders holding 66 2/3 percent of our commitments), may each request one special redetermination. We will be permitted to have security 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.

The Credit Facilities require us to apply 50% of the proceeds from certain transactions, including certain of the deleveraging transactions discussed above, to repay the Term Loan. We must also apply cash on hand in excess of $250 million to repay certain amounts outstanding under the Revolving Credit Facility. In addition, our ability to pay dividends or make other distributions to common stockholders is limited to $20 million per year. While we are subject to the borrowing base, the Credit Facilities require us to maintain the following financial covenants for the trailing twelve months ended as of the last day of each fiscal quarter: (a) a first lien senior secured leverage ratio of no more than 2.25 to 1.00 and (b) an interest expense ratio of no less than 2.00 to 1.00. At September 30, 2015, we were in compliance with the financial and other covenants under our Credit Facilities as they existed at that time. If we were to breach any of these covenants, our lenders would be permitted to accelerate the principal amount due under the facilities. If payment were accelerated it would result in a default under our notes described below.

Senior Notes

We will pay interest on the 2020 notes semi-annually in cash in arrears on January 15 and July 15 of each year, beginning on July 15, 2015. We will pay interest on the 2021 notes semi-annually in cash in arrears on March 15 and September 15 of each year, beginning on March 15, 2015. We will pay interest on the 2024 notes semi-annually in cash in arrears on May 15 and November 15 of each year, beginning on May 15, 2015.

The indenture governing the notes includes covenants that, among other things, limit our and our restricted subsidiaries’ ability to incur debt secured by liens. These covenants 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 coupled with a credit rating decline below investment grade, we will be required to offer to purchase the notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest or to have exercised our redemption right.

Cash Flow Analysis



	Nine months ended September 30,
	2015			2014
	(in millions)
Net cash flows provided by operating activities	$	412		$	1,867
Net cash flows used in investing activities	$	(542	)	$	(1,614	)
Net cash flows provided / (used) by financing activities	$	120		$	(148	)
Adjusted EBITDAX ⁽¹⁾	$	680		$	2,094

_______________________________

(1)

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,
	2015			2014
	(in millions)
Net cash provided by operating activities	$	412		$	1,867
Interest expense	244			—
Cash income taxes	—			182
Cash exploration expenses	20			19
Changes in operating assets and liabilities	43			12
Other non-cash items, net	(39		)	14
Adjusted EBITDAX	$	680		$	2,094

Our net cash provided by operating activities decreased by approximately $1.5 billion, to $412 million for the nine months ended September 30, 2015, compared to the same period of 2014. The decrease reflected lower revenue of approximately $1.5 billion mainly due to lower product prices, $244 million of higher interest expense, partially offset by the absence of cash income taxes of $182 million, lower operating costs of $80 million and working capital reductions of $30 million.

Our cash flow used in investing activities decreased approximately $1.1 billion for the nine months ended September 30, 2015 from $1.6 billion in 2014. The decrease largely reflected our lower capital investments of $323 million in 2015, compared to $1.6 billion in 2014. Additionally, the 2015 investing activities included approximately $200 million of 2014 capital investments paid in 2015.

Our net cash flow provided by financing activities increased by approximately $270 million for the nine months ended September 30, 2015, compared to the same period of 2014. The change reflected net proceeds from the Revolving Credit Facility of approximately $120 million in 2015 and net distributions to Occidental of approximately $150 million in 2014.

2015 Capital Program

We develop our capital investment programs by prioritizing life of project returns to grow our net asset value over the long term, while balancing the short- and long-term growth potential of each of our assets. We use the Value Creation Index (VCI) metric for project selection and capital allocation across our portfolio of opportunities. The VCI for each project is calculated by dividing the present value of the project's expected pre-tax cash flow over its life by the present value of the investments, each using a 10% discount rate. Projects are expected to meet a VCI of 1.3, including the return of capital, meaning that 30% of expected value is created above our cost of capital for every dollar invested.

In light of current commodity prices, our focus on creating value and our commitment to internally fund our capital program with operating cash flows, we have significantly reduced our capital investment budget for 2015 to $440 million, as compared to $2.1 billion in 2014. We have focused substantially all of our 2015 program on our mature steamfloods, waterfloods and capital workovers, which have much lower expected decline rates than many unconventional projects. Capital investments in the first three quarters of 2015 have been running below budgeted amounts, largely due to efficiencies we have implemented across all aspects of our business, while exceeding the goals of our capital program. The resulting savings will be used to repay borrowings and to fund additional capital workovers in the fourth quarter of 2015.

Our 2015 capital investment program targets investments in the San Joaquin, Los Angeles and Ventura basins, and is expected to be directed almost entirely towards higher-margin, higher-return and low-decline crude oil projects, consistent with 2014. Of the total 2015 program, approximately $150 million is expected to be allocated to drilling wells, $50 million to workovers, $130 million to additional steam-generation capacity and compression

expansion, $15 million to exploration and the rest to 3D seismic, maintenance capital, occupational health, safety and environmental projects and other items. We will also continue to pursue and fund our most attractive unconventional projects when they meet our VCI criteria.

The table below sets forth our 2015 capital investments for the nine months ended September 30, 2015:



	Conventional								Unconventional		Other		Total Capital Investments
	Primary		Waterflood		Steamflood		Total		Primary		Other		Total Capital Investments
Basin:
San Joaquin	$	43	$	12	$	117	$	172	$	17	$	—	$	189
Los Angeles	—		74		—		74		—		—		74
Ventura	11		7		2		20		—		—		20
Sacramento	—		—		—		—		—		—		—
Basin Total	54		93		119		266		17		—		283
Exploration and Other	—		—		—		—		—		40		40
Total	$	54	$	93	$	119	$	266	$	17	$	40	$	323

In addition, during this period of lower capital investment, we will continue to take advantage of the lower activity levels to redeploy our existing resources to build our project inventory and further refine and enhance our production techniques. We plan to position ourselves so we can rapidly take advantage of a more favorable pricing environment.

Lawsuits, Claims, Contingencies and Commitments

Significant Accounting and Disclosure Changes

In July 2015, the Financial Accounting Standards Board (FASB) issued rules requiring entities to measure inventory within the scope of these rules at the lower of cost and net realizable value. These new rules do not apply to inventory that is measured using last-in, first-out or the retail inventory method and will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The rules must be applied prospectively with earlier application permitted. We do not expect these new rules to have a significant impact on our financial statements.

within those fiscal years, with early adoption of the rules permitted. We do not expect the disclosure changes to have a significant impact on our financial statements.

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, drilling program, 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. 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 2014 Form 10-K and Item 1A of this Form 10-Q.

Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the effect of our debt on our financial flexibility; sufficiency of our operating cash flow to fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; our ability 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; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; limitations on our ability to enter efficient hedging transactions; 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; 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, 2015, 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 2014 Form 10-K, except for the following matters.

Commodity Price Risk

Derivatives

As of October 31, 2015, our existing hedge positions were as follows:


•	Weighted average Brent-based floors and ceilings of $61.25 per barrel and $73.88 per barrel, respectively, for 40,000 barrels per day of our fourth quarter 2015 oil production;


•	Brent-based hedges with a weighted average floor of $52.38 per barrel and a ceiling of $66.15 per barrel for 30,500 barrels per day and 35,500 barrels per day, respectively, of our January through June 2016 crude oil production;


•	Brent-based hedges with a floor of $50 per barrel and a weighted average ceiling of $74.42 per barrel for 3,000 barrels per day of our July through December 2016 oil production;


•	Index-based hedges at an average price of $3.01 per million British thermal units (MMBtu) for 40,000 MMBtu per day and weighted average floors and ceilings of $2.80 per MMBtu and $3.17 per MMBtu, respectively, for 20,000 MMBtu per day of our fourth quarter 2015 natural gas production.

Counterparty 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 our derivatives, we are subject to counterparty credit risk to the extent the counterparty associated with a specific derivative is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and by continuing to monitor their financial health.

As of September 30, 2015, 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, 2015 was not material and losses associated with credit risk have been insignificant for all periods 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, 2015.

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 2015 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 and combined 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, 2014.


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, 2014 and below:

Our lenders can limit our borrowing capabilities, which may materially impact our ability to access capital for capital expenditures and operations.

At September 30, 2015, we had approximately $481 million of outstanding debt under our Revolving Credit Facility. Effective November 2, 2015, our initial borrowing base was $3.0 billion and commitments from our bank group under our Revolving Credit Facility totaled $2.0 billion. The borrowing base under our credit facility is redetermined annually based upon a number of factors, including commodity prices and reserve levels. As a result the estimated value of our reserves may not exceed our initial borrowing base by as much as it does today or may be less than our inital borrowing base, in which case our borrowing base would be adjusted. In addition, between redeterminations we and, if requested by lenders holding 66 2/3 percent of our commitments, our lenders, may each request one special redetermination. Upon a redetermination, our borrowing base could be substantially reduced, and in the event the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. We expect to utilize cash flow from operations and bank borrowings to fund our development, exploration and acquisition activities and manage working capital fluctuations. A reduction in our borrowing base could limit our activities.


Item 5.	Other Disclosures

On November 2, 2015, we entered into a second amendment to our Credit Facilities with our senior lenders. The second amendment modified financial and other covenants and certain other terms as described in the "Liquidity and Capital Resources" portion of this Form 10-Q.


Item 6.	Exhibits



	10.1	Second Amendment to Credit Agreement, dated as of November 2, 2015, among California Resources Corporation, the Lenders and JPMorgan 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.

	10.2	Form of 2015 Performance Stock Unit Award Terms and Conditions.

	10.3	Form of 2015 Restricted Stock Unit Award Terms and Conditions.

	10.4	Form of 2015 Nonstatutory Stock Option 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.

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 5, 2015	/s/ Roy Pineci
		Roy Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)

EXHIBIT INDEX

EXHIBITS



	10.1	Second Amendment to Credit Agreement, dated as of November 2, 2015, among California Resources Corporation, the Lenders and JPMorgan 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.

	10.2	Form of 2015 Performance Stock Unit Award Terms and Conditions.

	10.3	Form of 2015 Restricted Stock Unit Award Terms and Conditions.

	10.4	Form of 2015 Nonstatutory Stock Option 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.