CRC 10Q 6.30.2015

10-Q 1 crc10q6302015.htm 10-Q CRC 10Q 6.30.2015

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 June 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)

10889 Wilshire Blvd., Los Angeles, California, 90024

(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 June 30, 2015	386,380,829

California Resources Corporation and Subsidiaries

Table of Contents



				PAGE

Part I	Financial Information

	Item 1.	Financial Statements (unaudited)

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

		Consolidated Condensed Statements of Operations —
			Three and six months ended June 30, 2015 and 2014	3

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

		Consolidated Condensed Statements of Cash Flows —
			Six months ended June 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	14

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		28

	Item 4.	Controls and Procedures		28

Part II	Other Information

	Item 1.	Legal Proceedings		29

	Item 1A.	Risk Factors		29

	Item 6.	Exhibits		29

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

(in millions)





	June 30,			December 31,
	2015			2014

CURRENT ASSETS

Cash and cash equivalents	$	37		$	14
Trade receivables, net	268			308
Inventories	74			71
Other current assets	277			308
Total current assets	656			701

PROPERTY, PLANT AND EQUIPMENT	20,745			20,536
Accumulated depreciation, depletion and amortization	(9,335		)	(8,851		)
	11,410			11,685

OTHER ASSETS	51			43

TOTAL ASSETS	$	12,117		$	12,429



CURRENT LIABILITIES

Current maturities of long-term debt	$	50		$	—
Accounts payable	278			588
Accrued liabilities	357			334
Total current liabilities	685			922

LONG-TERM DEBT, NET	6,476			6,292

DEFERRED INCOME TAXES	1,941			2,055

OTHER LONG-TERM LIABILITIES	560			549

EQUITY

Preferred stock (200 million shares authorized at $0.01 par value) no shares outstanding at June 30, 2015 and December 31, 2014	—			—
Common stock (2.0 billion shares authorized at $0.01 par value) outstanding shares (June 30, 2015 - 386,380,829 and December 31, 2014 - 385,639,582)	4			4
Additional paid-in capital	4,766			4,748
Accumulated deficit	(2,293		)	(2,117		)
Accumulated other comprehensive income / (loss)	(22		)	(24		)

Total equity	2,455			2,611

TOTAL LIABILITIES AND EQUITY	$	12,117		$	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 six months ended June 30, 2015 and 2014

(in millions)



	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
REVENUES
Oil and natural gas net sales to third parties	$	609		$	28		$	1,158		$	48
Oil and natural gas net sales to related parties	—			1,079			—			2,139
Other revenue	25			33			53			74
	634			1,140			1,211			2,261
COSTS AND OTHER DEDUCTIONS
Production costs	242			270			484			534
General and administrative expenses	85			71			161			140
Depreciation, depletion and amortization	251			293			504			582
Taxes other than on income	53			55			108			107
Exploration expense	7			15			24			46
Interest and debt expense, net	83			—			162			—
Other expenses	27			28			51			70
	748			732			1,494			1,479

INCOME / (LOSS) BEFORE INCOME TAXES	(114		)	408			(283		)	782
Income tax (expense) / benefit	46			(162		)	115			(313		)
NET INCOME / (LOSS)	$	(68	)	$	246		$	(168	)	$	469

Net income / (loss) per share of common stock
Basic	$	(0.18	)	$	0.63		$	(0.44	)	$	1.21
Diluted	$	(0.18	)	$	0.63		$	(0.44	)	$	1.21

Dividends per common share	$	0.01		$	—		$	0.02		$	—

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 six months ended June 30, 2015 and 2014

(in millions)



	Three months ended June 30,					Six months ended June 30,
	2015			2014		2015			2014
Net income / (loss)	$	(68	)	$	246	$	(168	)	$	469
Other comprehensive income / (loss) items:
Unrealized losses on derivatives ^(a)	—			—		—			(2		)
Pension and postretirement (losses) / gains ^(b)	(3		)	—		(3		)	1
Reclassification to income of realized losses on derivatives ^(c)	—			—		—			3
Reclassification to income of realized losses on pension and postretirement ^(d)	5			—		5			—
Other comprehensive income / (loss), net of tax	2			—		2			2
Comprehensive income / (loss)	$	(66	)	$	246	$	(166	)	$	471

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

(b) Net of tax of $2 million and zero for the three months ended June 30, 2015 and 2014, respectively. Net of tax of $2 million and zero for the six months ended June 30, 2015 and 2014, respectively. See Note 10, Retirement and Postretirement Benefit Plans, for additional information.

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

(d) Net of tax of ($3) million and zero for the three months ended June 30, 2015 and 2014, respectively. Net of tax of ($3) million and zero for the six months ended June 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 six months ended June 30, 2015 and 2014

(in millions)



	2015			2014
CASH FLOW FROM OPERATING ACTIVITIES
Net income / (loss)	$	(168	)	$	469
Adjustments to reconcile net income / (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	504			582
Deferred income tax expense / (benefit)	(115		)	178
Other noncash charges to income	54			22
Dry hole expenses	7			32
Changes in operating assets and liabilities, net	(50		)	(47		)
Net cash provided by operating activities	232			1,236

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(228		)	(1,003		)
Changes in capital investment accruals	(203		)	(1		)
Acquisitions and other	(9		)	(35		)
Net cash used by investing activities	(440		)	(1,039		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from revolving credit facility	1,164			—
Repayments of revolving credit facility	(934		)	—
Proceeds from issuance of common stock	5			—
Cash dividends paid	(4		)	—
Distributions to Occidental, net	—			(197		)
Net cash provided / (used) by financing activities	231			(197		)
Increase in cash and cash equivalents	23			—
Cash and cash equivalents—beginning of period	14			—
Cash and cash equivalents—end of period	$	37		$	—

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Condensed Financial Statements

June 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 have assumed in connection with the Spin-off, and (3) all references to Occidental refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries.

Basis of Presentation

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 six months ended June 30, 2015, as applicable, consist of our stand-alone consolidated results following the Spin-off, and the three and six months ended June 30, 2014 consist of the combined results of the California business.


•	Our consolidated balance sheets at June 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 June 30, 2015, and the statements of operations, comprehensive income, and cash flows for the three and six months ended June 30, 2015 and 2014, as applicable. The income / (loss) and cash flows for the periods ended June 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 2015, we changed the classification of certain employee-related costs between general and administrative expenses and 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 May 2015, the Financial Accounting Standards Board (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 June 30, 2015 and December 31, 2014, include amounts due from joint interest partners of approximately $120 million each, deferred tax assets of $60 million each, and greenhouse gas emission credits of $40 million and $65 million, respectively.

Accrued liabilities at June 30, 2015 and December 31, 2014, include accrued compensation-related costs of approximately $95 million each, interest payable of $85 million and $70 million and greenhouse gas liabilities of $70 million and $65 million, respectively. Other long-term liabilities include asset retirement obligations of $396 million and $397 million at June 30, 2015 and December 31, 2014, respectively.

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 six-month period ended June 30, 2015. Interest paid totaled approximately $149 million and zero for the six months ended June 30, 2015 and 2014, respectively.

NOTE 4 INVENTORIES

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



	2015		2014
	(in millions)
Materials and supplies	$	70	$	66
Finished goods	4		5
Total	$	74	$	71

NOTE 5 DEBT

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



	2015			2014
	(in millions)
Revolving Credit Facility	$	590		$	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	6,590			6,360

Less: Current maturities of long-term debt	(50		)	—

Less: Deferred financing costs	(64		)	(68		)

Total long-term debt, net	$	6,476		$	6,292

Credit Facilities

On September 24, 2014, we entered into a credit agreement with a syndicate of lenders, providing 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. We amended the Credit Facilities effective as of February 25, 2015, and changed certain of our covenants through December 31, 2016 or such earlier time as we elect and demonstrate compliance with our original covenants for two successive quarters (the Interim Covenant Period).

The aggregate commitments of the lenders are $2.0 billion — effectively reduced to $1.25 billion during the Interim Covenant Period — and $1.0 billion under the Revolving Credit Facility and 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 June 30, 2015, we had $590 million outstanding under our Revolving Credit Facility with the ability to incur additional borrowings of up to $697 million under this facility after taking into account our cash balance.

margin is based on our most recent leverage ratio and will vary from (a) in the case of LIBOR loans, 1.50% to 2.25% and (b) in the case of ABR loans, 0.50% to 1.25%. The unused portion of the Revolving Credit Facility is subject to commitment fees ranging from 0.30% to 0.50% per annum, based on our most recent leverage ratio. We also pay customary fees and expenses under the Revolving Credit Facility. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period.

All obligations under the Credit Facilities are guaranteed jointly and severally by all of our wholly-owned material subsidiaries, and will not be required to be secured so long as we maintain our credit ratings at the minimum levels defined in the Credit Facilities. During the remaining Interim Covenant Period, we would be required to grant security to our lenders if our corporate family ratings experienced a one-notch decline from Moody's Investors Service or a two-notch decline from Standard & Poor's Ratings Services. The assets and liabilities of subsidiaries not guaranteeing the debt are de minimis.

The Credit Facilities also 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 leverage ratio of no more than 4.50 to 1.00 except during the Interim Covenant Period when the ratio increases to 4.75 to 1.00 as of June 30, 2015, 6.25 to 1.00 as of September 30, 2015 and 8.25 to 1.00 as of December 31, 2015 and then decreases to 8.00 to 1.00 as of March 31, 2016, 7.25 to 1.00 as of June 30, 2016, 6.75 to 1.00 as of September 30, 2016, 6.25 to 1.00 as of December 31, 2016 and 4.50 to 1.00 thereafter and (b) an interest expense ratio of no less than 2.50 to 1.00 except as of December 31, 2015 when the ratio must be no less than 2.25 to 1.00. In addition, during the Interim Covenant Period, we must maintain an asset coverage ratio of no less than 1.05 to 1.00 measured as of the last day of each fiscal quarter. Finally, during the Interim Covenant Period, we must apply cash on hand in excess of $250 million to repay certain amounts outstanding under the Revolving Credit Facility. If we were to breach any of these covenants the banks would be permitted to accelerate the principal amount due under the facilities. If payment were accelerated it would result in a default under the notes.

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.

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, 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 June 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 $5.9 billion and $5.6 billion, respectively, compared to a net carrying value of approximately $6.5 billion and $6.3 billion. A one-eighth percent change in the variable interest rates on the borrowings under our Term Loan Facility and Revolving Credit Facility on June 30, 2015, would result in an approximately $2 million change in annual interest expense.

As of June 30, 2015 and December 31, 2014, we had letters of credit in the aggregate amount of approximately $27 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 June 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 June 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, any fair value gains or losses, over the remaining term of the hedge instrument, are recognized in earnings in the current period. We recognized approximately $17 million and $20 million of net derivative losses from marking these contracts to market, which were included in net sales, for the three and six months ended June 30, 2015, respectively.

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


•	Weighted average Brent-based floors of $52.14 per barrel for 70,000 barrels per day of our third quarter 2015 oil production;


•	Brent-based ceilings of $72.12 per barrel for 30,000 barrels per day of our third quarter 2015 oil production;


•	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 hedge at $72.05 per barrel for 2,000 barrels per day of our total year 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 second half 2015 natural gas production.

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 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.

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 six-month periods ended June 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 six-month periods ended June 30, 2015 and 2014.

Fair Value of Derivatives

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

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



	Asset Derivatives			Liability Derivatives
June 30, 2015	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Other current assets	$	18	Accrued Liabilities	$	(9	)

Total gross and net fair value		$	18		$	(9	)

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 June 30, 2015 and December 31, 2014 (in millions):



	June 30, 2015
	Level 1		Level 2		Level 3		Collateral		Total
Assets:
Commodity derivative instruments, other current assets	$	—	$	18	$	—	$	—	$	18
Liabilities:
Commodity derivative instruments, accrued liabilities	$	—	$	9	$	—	$	—	$	9



	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 six months ended June 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 six months ended June 30, 2015 we issued approximately 365,000 shares and 735,000 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 six months ended June 30, 2015.

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



	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
	(in millions, except per-share amounts)
Basic EPS calculation
Net income / (loss)	$	(68	)	$	246		$	(168	)	$	469
Net income / (loss) allocated to participating securities	—			(4		)	—			(8		)
Net income / (loss) available to common stockholders	$	(68	)	$	242		$	(168	)	$	461

Weighted-average common shares outstanding - basic	382.7			381.8			382.4			381.8
Basic EPS	$	(0.18	)	$	0.63		$	(0.44	)	$	1.21

Diluted EPS calculation
Net income / (loss)	$	(68	)	$	246		$	(168	)	$	469
Net income / (loss) allocated to participating securities	—			(4		)	—			(8		)
Net income / (loss) available to common stockholders	$	(68	)	$	242		$	(168	)	$	461

Weighted average common shares outstanding - basic	382.7			381.8			382.4			381.8
Dilutive effect of potentially dilutive securities	—			—			—			—
Weighted-average common shares outstanding - diluted	382.7			381.8			382.4			381.8
Diluted EPS	$	(0.18	)	$	0.63		$	(0.44	)	$	1.21

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 June 30,
		2015					2014
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	1		$	1	$	1		$	1
Interest cost		1			1		1			1
Expected return on plan assets		(1	)		—		(1	)		—
Recognized actuarial loss		1			—		1			—
Settlements		8			—		—			—
Total	$	10		$	2	$	2		$	2



	Six months ended June 30,
		2015					2014
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	2		$	2	$	2		$	2
Interest cost		2			2		2			2
Expected return on plan assets		(2	)		—		(3	)		—
Recognized actuarial loss		1			—		1			—
Settlements		8			—		—			—
Total	$	11		$	4	$	2		$	4

We contributed $3 million to our defined benefit pension plans during the three months ended June 30, 2015. We did not make any contributions during the three months ended March 31, 2015 or either of the three- or six-month periods ended June 30, 2014. The 2015 settlements 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 six months ended June 30, 2014, related party sales included oil and natural gas products of $1,079 million and $2,139 million, respectively, and power (reflected in other revenue) of $28 million and $66 million, respectively.

Purchases from related parties reflect products purchased at market prices from Occidental’s subsidiaries and used in our operations. These purchases were approximately $100 million and $120 million for the three and six months ended June 30, 2014, respectively, and were included in production costs. There were no significant related-party receivable or payable balances at June 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 $40 million and $75 million for the three and six months ended June 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 have 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 2015, we changed the classification of certain employee-related costs between general and administrative expenses and 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.

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 in case of further price deterioration. As of June 30, 2015, our existing hedge positions were as follows:


•	Weighted average Brent-based floors of $52.14 per barrel for 70,000 barrels per day of our third quarter 2015 oil production;


•	Brent-based ceilings of $72.12 per barrel for 30,000 barrels per day of our third quarter 2015 oil production;


•	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 hedge at $72.05 per barrel for 2,000 barrels per day of our total year 2016 oil production.

The following graph represents our oil hedges as of June 30, 2015:

In addition, for our second half 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 second quarter of 2015 and for the first half of the year 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 have improved in the second quarter of 2015 as the effect of these events has dissipated and have begun to approach historical norms.

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



	Three months ended June 30,				Six months ended June 30,
	2015		2014		2015		2014
Brent oil ($/Bbl)	$	63.50	$	109.77	$	59.33	$	108.83
WTI oil ($/Bbl)	$	57.94	$	102.99	$	53.29	$	100.84
NYMEX gas ($/MMBtu)	$	2.74	$	4.55	$	2.90	$	4.60

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 get 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 2.4 million net acres, approximately 60% of which we hold in fee. Our oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. We also own a network of strategically placed infrastructure 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 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 six months ended June, 30, 2015, we had a net loss of $68 million and $168 million, or ($0.18) and ($0.44) per diluted share, respectively, and an adjusted net loss of $51 million and $148 million, or ($0.13) and ($0.39) per diluted share. For the three and six months ended June 30, 2014, both net income and adjusted net income were $246 million and $469 million, or $0.63 and $1.21 per diluted share, respectively. The table below reconciles net income / (loss) to adjusted net income / (loss):



	Three months ended June 30,					Six months ended June 30,
	2015			2014		2015			2014
	(in millions)
Net income / (loss)	$	(68	)	$	246	$	(168	)	$	469
Hedge related activity	17			—		20			—
Early retirement and severance costs	10			—		10			—
Rig terminations and other	1			—		3			—
Tax effect of pre-tax adjustments	(11		)	—		(13		)	—
Adjusted net income / (loss)	$	(51	)	$	246	$	(148	)	$	469

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).

Results from the second quarter of 2015, compared to the same period in 2014, reflected higher production, in particular oil volumes, and lower production costs and depreciation, depletion and amortization expense (DD&A), offset by significantly lower realized oil, NGL and gas prices and higher interest expense as a result of our capital structure as an independent company.

Daily oil and gas production volumes averaged 161,000 barrels of oil equivalent (BOE) in the second quarter of 2015, compared with 156,000 BOE in the second quarter of 2014. Average oil production increased by 7% or 7,000 barrels per day to 104,000 barrels per day in the second quarter of 2015. NGL production remained the same while natural gas production decreased approximately 4%.

Realized crude oil prices decreased 46% to $56.73 per barrel in the second quarter of 2015 from $104.50 per barrel in the second quarter of 2014. The decrease mainly reflected the drop in global oil prices, as the Brent index decreased 42% year-over-year. Additionally, our realized prices reflect higher differentials to Brent compared to historical levels due in part to the residual effects of market disruptions in California earlier in 2015, like refinery interruptions. Realized NGL prices decreased 58% to $20.47 per barrel in the second quarter of 2015 from $49.08 per barrel in the second quarter of 2014. Natural gas realized prices decreased 45% in the second quarter of 2015 to $2.49 per Mcf, compared with $4.52 per Mcf in the second quarter of 2014. The decrease in natural gas prices has been driven by the mild California weather in the first half of 2015, resulting in higher than normal storage in the California natural gas markets.

In the second quarter of 2015, we continued to run three drilling rigs with two focused in the San Joaquin basin and one in the Los Angeles basin. In the San Joaquin basin, the rigs drilled 93 steamflood wells including 66 wells in the Lost Hills field, 16 in the Kern Front field and six in Midway Sunset field. In the Los Angeles basin, we drilled 10 waterflood wells in the Wilmington field. As a result of capital efficiencies across the company, we have drilled eight more wells than our plan year-to-date. In addition, during the second quarter, we completed 123 capital workovers and substantially completed a significant compression project in the San Joaquin basin.

The first six months in 2015, compared to the same period of 2014, reflected higher production, in particular oil volumes, and lower production costs, DD&A and exploration expense, offset by significantly lower realized product prices in 2015 and higher interest expense as a result of our capital structure as an independent company.

For the first six months of 2015, daily production averaged 163,000 BOE, compared with 155,000 in the first six months of 2014. Average oil production increased 10,000 barrels per day, or by 10% to 106,000 barrels per day in 2015. NGL production remained the same and natural gas production decreased approximately 2%.

Realized crude oil prices decreased 50% to $51.51 per barrel for the first six months of 2015 from $103.43 per barrel for the first six months of 2014. NGL prices decreased 62% to $21.00 per barrel in the first six months of 2015 from $54.86 per barrel for the first six months of 2014. Natural gas prices decreased 43% to $2.67 per Mcf in the first six months of 2015, compared with $4.67 per Mcf in the first six months of 2014.

The following table sets forth our average production volumes of oil, NGLs and natural gas per day for the three- and six-month periods ended June 30, 2015 and 2014:



	Three months ended June 30,		Six months ended June 30,
	2015	2014	2015	2014
Oil (MBbl/d)
San Joaquin Basin	67	62	67	62
Los Angeles Basin	31	29	33	28
Ventura Basin	6	6	6	6
Sacramento Basin	—	—	—	—
Total	104	97	106	96

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

Natural gas (MMcf/d)
San Joaquin Basin	175	182	177	177
Los Angeles Basin	2	—	2	—
Ventura Basin	11	12	12	12
Sacramento Basin	46	49	47	54
Total	234	243	238	243

Total Production (MBoe/d)^(a)	161	156	163	155

_________________________


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 six months ended June 30, 2015, the average prices of Brent oil and NYMEX natural gas were $59.33 per barrel and $2.90 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 June 30,				Six months ended June 30,
	2015		2014		2015		2014
Oil Prices ($ per Bbl)	$	56.73	$	104.50	$	51.51	$	103.43
NGLs Prices ($ per Bbl)	$	20.47	$	49.08	$	21.00	$	54.86
Gas Prices ($ per Mcf)	$	2.49	$	4.52	$	2.67	$	4.67

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



	Three months ended June 30,				Six months ended June 30,
	2015		2014		2015		2014
Brent oil	89	%	95	%	87	%	95	%
WTI oil	98	%	101	%	97	%	103	%
NYMEX gas	91	%	99	%	92	%	102	%

Balance Sheet Analysis

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



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

Cash and cash equivalents	$	37	$	14
Trade receivables, net	$	268	$	308
Inventories	$	74	$	71
Other current assets	$	277	$	308
Property, plant and equipment, net	$	11,410	$	11,685
Other assets	$	51	$	43



Current maturities of long-term debt	$	50	$	—
Accounts payable	$	278	$	588
Accrued liabilities	$	357	$	334
Long-term debt, net	$	6,476	$	6,292
Deferred income taxes	$	1,941	$	2,055
Other long-term liabilities	$	560	$	549
Equity	$	2,455	$	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 second quarter of 2015, compared to the fourth quarter of 2014, partially offset by higher oil volumes. The decrease in other current assets was mainly due to a reduction in our greenhouse gas credits that are in place for future use. The decrease in property, plant and equipment reflected depreciation, depletion and amortization (DD&A) for the period, partially offset by capital investments.

The increase in current maturities of long-term debt reflected the 2016 first and second quarterly payments due on the term loan facility. The decrease in accounts payable reflected the payments related to the high level of capital investment in the fourth quarter of 2014, compared to the lower capital investments made in 2015. The increase in accrued liabilities was mainly due to the timing of interest payments. The decrease in deferred income taxes was mainly due to our net loss for the period, which resulted in net operating losses. The decrease in equity mainly reflected the net loss for the six-month period in 2015.

Statement of Operations Analysis

The following table presents the results of our operations:



	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
	(in millions)
Oil and gas net sales (including related parties)	$	609		$	1,107		$	1,158		$	2,187
Other revenue	25			33			53			74
Production costs	(242		)	(270		)	(484		)	(534		)
General and administrative expenses	(85		)	(71		)	(161		)	(140		)
Depreciation, depletion and amortization	(251		)	(293		)	(504		)	(582		)
Taxes other than on income	(53		)	(55		)	(108		)	(107		)
Exploration expense	(7		)	(15		)	(24		)	(46		)
Interest and debt expense, net	(83		)	—			(162		)	—
Other expenses	(27		)	(28		)	(51		)	(70		)
Income tax (expense) / benefit	46			(162		)	115			(313		)
Net income / (loss)	$	(68	)	$	246		$	(168	)	$	469

Adjusted net income / (loss)	$	(51	)	$	246		$	(148	)	$	469
Adjusted EBITDAX⁽¹⁾	$	270		$	727		$	468		$	1,432

Effective tax rate	40		%	40		%	41		%	40		%

________________________

(1)

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 June 30,					Six months ended June 30,
	2015			2014		2015			2014
	(in millions)
Net income / (loss)	$	(68	)	$	246	$	(168	)	$	469
Interest expense	83			—		162			—
Income tax expense / (benefit)	(46		)	162		(115		)	313
Depreciation, depletion and amortization	251			293		504			582
Exploration expense	7			15		24			46
Other	43			11		61			22
Adjusted EBITDAX	$	270		$	727	$	468		$	1,432

The following represents key metrics of our oil and gas operations, excluding certain corporate items, on a per BOE basis for the three and six months ended June 30:



	Three months ended June 30,				Six months ended June 30,
	2015		2014		2015		2014
Production costs	$	16.59	$	19.03	$	16.39	$	19.02
Depreciation, depletion and amortization	$	16.72	$	20.27	$	16.60	$	20.37
Taxes other than on income	$	3.24	$	3.55	$	3.27	$	3.47

Three Months Ended June 30, 2015 vs. 2014

Net sales decreased 45%, or $498 million, for the three months ended June 30, 2015, compared to the same period of 2014, mainly due to an approximately $450 million negative impact from lower oil prices, $50 million from lower NGL prices and $50 million from lower natural gas prices and volumes. The decreases were partially offset by a $60 million positive impact from higher oil volumes. Average oil production increased by 7% or 7,000 barrels per day to 104,000 barrels per day in the second quarter of 2015. NGL production remained the same while natural gas production decreased approximately 4%.

Other revenue decreased 24%, or $8 million, for the three months ended June 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 from California power utilities.

Production costs for the three months ended June 30, 2015 decreased $28 million, to $242 million or $16.59 per BOE, compared to $270 million or $19.03 per BOE for the same period of 2014, resulting in a 13% decrease on a per BOE basis. The lower costs in 2015 reflect our ongoing cost reduction and efficiency efforts. These efforts have resulted in reductions in most categories, including surface operations and improved well servicing efficiency, resulting in lower workover and downhole maintenance costs. Costs of energy and gas used for steamflood injections were also lower as a result of lower prices. Unit costs also benefited from higher production volumes in 2015.

General and administrative (G&A) expenses for the three months ended June 30, 2015 included infrequent costs of approximately $10 million associated with early retirements and severance costs as part of our ongoing effort to rationalize our cost structure. Our adjusted G&A expense per barrel, which excludes this charge, was $5.13, which was comparable to the prior year quarter.

DD&A expense decreased 14%, or $42 million, for the three months ended June 30, 2015, compared to the same period of 2014. Of this decrease, approximately $50 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 approximately $10 million attributable to higher volumes.

Taxes other than on income, which consist largely of ad valorem taxes, greenhouse gas credits and production taxes, for the three months ended June 30, 2015 were comparable to the same period of 2014.

Exploration expense decreased 53%, or $8 million, for the three months ended June 30, 2015, compared to the same period of 2014, consistent with our reduced exploration activity.

Interest and debt expense, net, of $83 million for the second quarter of 2015 was associated with the debt we incurred in connection with the Spin-off in the fourth quarter of 2014.

Other expenses for the three months ended June 30, 2015 were comparable to the same period of 2014.

Income tax (expense) / benefit showed a benefit of $46 million for the three months ended June 30, 2015, reflecting a pre-tax loss of $114 million for the quarter, compared to a provision of $162 million in the same period of 2014, reflecting pre-tax income of $408 million. The effective tax rate was comparable between periods.

Six Months Ended June 30, 2015 vs. 2014

Net sales decreased 47%, or $1,029 million, for the six months ended June 30, 2015, compared to the same period of 2014, mainly due to an approximately $990 million negative impact from lower oil prices, $110 million from lower NGL prices and $90 million from lower natural gas prices and volumes. The decreases were partially offset by an approximately $180 million positive impact from higher oil volumes. Average oil production increased by 10% or 10,000 barrels per day to 106,000 barrels per day in the first six months of 2015. NGL production remained the same and natural gas production decreased approximately 2%.

Other revenue decreased 28%, or $21 million, for the six months ended June 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 from California power utilities.

Production costs for the six months ended June 30, 2015 decreased $50 million, to $484 million or $16.39 per BOE, compared to $534 million or $19.02 per BOE for the same period of 2014, resulting in a 14% decrease on a per BOE basis. The lower costs in 2015 reflect our ongoing cost reduction and efficiency efforts. These efforts have resulted in reductions in most categories, including surface operations and improved well servicing efficiency, resulting in lower workover and downhole maintenance costs. Costs of energy and gas used for steamflood injections were also lower as a result of lower prices. Unit costs also benefited from higher production volumes in 2015.

G&A expenses for the six months ended June 30, 2015 included infrequent costs of approximately $10 million associated with early retirements and severance costs as part of our ongoing effort to rationalize our cost structure. Our adjusted G&A expense per barrel, which excludes this charge, was $5.11, which was comparable to the prior year period.

DD&A expense decreased 13%, or $78 million, for the six months ended June 30, 2015, compared to the same period of 2014. Of this decrease, approximately $105 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 $25 million attributable to higher volumes.

Taxes other than on income for the six months ended June 30, 2015 were comparable to the same period of 2014.

Exploration expense decreased 48%, or $22 million, for the six months ended June 30, 2015, compared to the same period of 2014, consistent with our reduced exploration activity.

Interest and debt expense, net, of $162 million for the six months ended June 30, 2015 was associated with the debt we incurred in connection with the Spin-off in the fourth quarter of 2014.

Other expenses decreased 27%, or $19 million, for the six months ended June 30, 2015, compared to the same period of 2014, due to lower natural gas costs for our Elk Hills power plant.

Income tax (expense) / benefit showed a benefit of $115 million for the six months ended June 30, 2015, reflecting a pre-tax loss of $283 million for the period, compared to a provision of $313 million in the same period of 2014, reflecting pre-tax income of $782 million. The effective tax rate was comparable between periods.

Liquidity and Capital Resources

The primary source of liquidity and capital resources to fund our capital programs 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 and dividends for at least the next twelve months will be met by cash generated from operations, and borrowings when necessary. At June 30, 2015, we had approximately $697 million available on our revolving credit facilities, after taking into account our cash balance. Operating cash flows are largely dependent on oil and natural gas prices and differentials, sales volumes and costs. If the current conditions persist, we expect our production levels will be affected as we intend to limit our capital program to a level consistent with our expected operating cash flows and not look to accelerate production in this price environment. We are pursuing a wide variety of alternatives with numerous possible parties to delever our balance sheet and to better align our capital structure for a more modest normalized commodity price environment. The deleveraging options we are exploring for both upstream and

midstream reflect the flexibility of our resource base, and may include a combination of asset monetizations, joint ventures and other opportunities. We cannot, however, provide any assurances with respect to the timing, terms or size of any transactions to deleverage our balance sheet or whether we can execute such a transaction at all.

Credit Facilities

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 most recent leverage ratio and will vary from (a) in the case of LIBOR loans, 1.50% to 2.25% and (b) in the case of ABR loans, 0.50% to 1.25%. The unused portion of the Revolving Credit Facility is subject to commitment fees ranging from 0.30% to 0.50% per annum, based on our most recent leverage ratio. We also pay customary fees and expenses under the Revolving Credit Facility. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period.

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.

Cash Flow Analysis



	Six months ended June 30,
	2015			2014
	(in millions)
Net cash flows provided by operating activities	$	232		$	1,236
Net cash flows used in investing activities	$	(440	)	$	(1,039	)
Net cash flows provided / (used) by financing activities	$	231		$	(197	)
Adjusted EBITDAX ⁽¹⁾	$	468		$	1,432

_______________________________

(1)

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:



	Six months ended June 30,
	2015		2014
	(in millions)
Net cash provided by operating activities	$	232	$	1,236
Interest expense	162		—
Cash income taxes	—		135
Cash exploration expenses	17		13
Changes in operating assets and liabilities	50		47
Other, net	7		1
Adjusted EBITDAX	$	468	$	1,432

Our net cash provided by operating activities decreased by approximately $1,004 million, to $232 million for the six months ended June 30, 2015, compared to the same period of 2014. The decrease reflected lower revenue of approximately $1,050 million mainly due to lower product prices and $162 million of higher interest expense, partially offset by lower cash income taxes of $135 million and lower operating costs of approximately $70 million.

Our cash flow used in investing activities decreased approximately $600 million for the six months ended June 30, 2015 from $1,039 million in 2014. The decrease largely reflected our lower capital investments of $228 million

in 2015, compared to $1.0 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 $430 million for the six months ended June 30, 2015, compared to the same period of 2014. The change reflected net proceeds from the revolving credit facility of $230 million in 2015 and distributions to Occidental of approximately $200 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 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. We will also continue to pursue and fund our most attractive unconventional projects when they meet our VCI criteria.

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. In the first half of 2015, we achieved capital efficiencies which reduced our capital levels for that period. The resulting savings will be considered for additional projects in the latter half of the year.

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



	Conventional								Unconventional		Other		Total Capital Investments
	Primary		Waterflood		Steamflood		Total		Primary		Other		Total Capital Investments
Basin:
San Joaquin	$	36	$	11	$	76	$	123	$	17	$	—	$	140
Los Angeles	—		48		—		48		—		—		48
Ventura	7		1		1		9		—		—		9
Sacramento	—		—		—		—		—		—		—
Basin Total	43		60		77		180		17		—		197
Exploration and Other	—		—		—		—		—		31		31
Total	$	43	$	60	$	77	$	180	$	17	$	31	$	228

In addition, during this period of lower capital investment, we will take advantage of the lower cost environment and 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

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. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances. 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.

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; 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, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business. 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 six months ended June 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 June 30, 2015, our existing hedge positions were as follows:


•	Weighted average Brent-based floors of $52.14 per barrel for 70,000 barrels per day of our third quarter 2015 oil production;


•	Brent-based ceilings of $72.12 per barrel for 30,000 barrels per day of our third quarter 2015 oil production;


•	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 hedge at $72.05 per barrel for 2,000 barrels per day of our total year 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 second half 2015 natural gas production.

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 June 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 June 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 June 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 second 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.


Item 6.	Exhibits



	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:	August 6, 2015	/s/ Roy Pineci
		Roy Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)

EXHIBIT INDEX

EXHIBITS



	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.