California Resources Corp - FORM 10-Q

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - California Resources Corp	Financial_Report.xls
EX-12 - RATIO OF EARNINGS TO FIXED CHARGES - California Resources Corp	crcexhibit12q12015.htm
EX-31.1 - CERTIFICATION OF CEO - California Resources Corp	crcexhibit31110q3312015.htm
EX-32.1 - CERTIFICATIONS OF CEO AND CFO - California Resources Corp	crcexhibit32110q3312015.htm
EX-31.2 - CERTIFICATION OF CFO - California Resources Corp	crcexhibit31210q3312015.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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.)

10889 Wilshire Blvd. Los Angeles, California* (Address of principal executive offices)		90024 (Zip Code)

(888) 848-4754

(Registrant’s telephone number, including area code)

_____________________

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. (See definition of "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 March 31, 2015	386,004,534

* In June 2015, CRC anticipates moving its principal executive offices to 9200 Oakdale Avenue, Suite 900, Los Angeles, California 91311.

California Resources Corporation and Subsidiaries

Table of Contents



				PAGE

Part I	Financial Information

	Item 1.	Financial Statements (unaudited)

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

		Consolidated Condensed Statements of Operations —
			Three months ended March 31, 2015 and 2014	3

		Consolidated Condensed Statements of Comprehensive Income —
			Three months ended March 31, 2015 and 2014	4

		Consolidated Condensed Statements of Cash Flows —
			Three months ended March 31, 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		27

	Item 4.	Controls and Procedures		27

Part II	Other Information

	Item 1.	Legal Proceedings		28

	Item 1A.	Risk Factors		28

	Item 6.	Exhibits		28

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

(in millions)





	March 31,			December 31,
	2015			2014

CURRENT ASSETS

Cash and cash equivalents	$	28		$	14
Trade receivables, net	241			308
Inventories	71			71
Other current assets	314			308
Total current assets	654			701

PROPERTY, PLANT AND EQUIPMENT	20,665			20,536
Accumulated depreciation, depletion and amortization	(9,099		)	(8,851		)
	11,566			11,685

OTHER ASSETS	44			43

TOTAL ASSETS	$	12,264		$	12,429



CURRENT LIABILITIES

Current maturities of long-term debt	$	25		$	—
Accounts payable	373			588
Accrued liabilities	337			334
Total current liabilities	735			922

LONG-TERM DEBT, NET	6,479			6,292

DEFERRED INCOME TAXES	1,986			2,055

OTHER LONG-TERM LIABILITIES	548			549

EQUITY

Preferred stock (200 million shares authorized at $0.01 par value) no shares outstanding at March 31, 2015 and December 31, 2014	—			—
Common stock (2.0 billion shares authorized at $0.01 par value) outstanding shares (March 31, 2015 - 386,004,534 and December 31, 2014 - 385,639,582)	4			4
Additional paid-in capital	4,757			4,748
Accumulated deficit	(2,221		)	(2,117		)
Accumulated other comprehensive income / (loss)	(24		)	(24		)

Total equity	2,516			2,611

TOTAL LIABILITIES AND EQUITY	$	12,264		$	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 months ended March 31, 2015 and 2014

(in millions)



	2015			2014
REVENUES
Oil and natural gas net sales to third parties	$	549		$	20
Oil and natural gas net sales to related parties	—			1,060
Other revenue	28			41
	577			1,121
COSTS AND OTHER DEDUCTIONS
Production costs	242			256
General and administrative expenses	76			77
Depreciation, depletion and amortization	253			289
Taxes other than on income	55			52
Exploration expense	17			31
Interest and debt expense, net	79			—
Other expenses	24			42
	746			747

INCOME / (LOSS) BEFORE INCOME TAXES	(169		)	374
Income tax (expense) / benefit	69			(151		)
NET INCOME / (LOSS)	$	(100	)	$	223

Net income / (loss) per share of common stock
Basic	$	(0.26	)	$	0.57
Diluted	$	(0.26	)	$	0.57

Dividends per common share	$	0.01		$	—

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Comprehensive Income

For the three months ended March 31, 2015 and 2014

(in millions)



	2015			2014
Net income / (loss)	$	(100	)	$	223
Other comprehensive income / (loss) items:
Unrealized losses on derivatives ^(a)	—			(2		)
Pension and postretirement gains ^(b)	—			1
Reclassification to income of realized losses on derivatives ^(c)	—			3
Other comprehensive income, net of tax	—			2
Comprehensive income / (loss)	$	(100	)	$	225

(a) Net of tax of zero and $1 million for the three months ended March 31, 2015 and 2014, respectively.

(b) There were no taxes in 2015 and 2014. See Note 10, Retirement and Postretirement Benefit Plans, for additional information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Cash Flows

For the three months ended March 31, 2015 and 2014

(in millions)



	2015			2014
CASH FLOW FROM OPERATING ACTIVITIES
Net income / (loss)	$	(100	)	$	223
Adjustments to reconcile net income / (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	253			289
Deferred income tax expense / (benefit)	(69		)	119
Other noncash charges to income	26			14
Dry hole expenses	6			24
Changes in operating assets and liabilities, net	(1		)	71
Net cash provided by operating activities	115			740

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(133		)	(475		)
Changes in capital investment accruals	(173		)	(24		)
Acquisitions and other	(7		)	(2		)
Net cash used by investing activities	(313		)	(501		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from revolving credit facility	757			—
Repayments of revolving credit facility	(547		)	—
Proceeds from issuance of common stock	2			—
Distributions to Occidental, net	—			(239		)
Net cash provided / (used) by financing activities	212			(239		)
Increase in cash and cash equivalents	14			—
Cash and cash equivalents—beginning of period	14			—
Cash and cash equivalents—end of period	$	28		$	—

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Condensed Financial Statements

March 31, 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 months ended March 31, 2015 consist of our stand-alone consolidated results following the Spin-off, and the three months ended March 31, 2014 consist of the combined results of the California business.


•	Our consolidated balance sheets at March 31, 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 March 31, 2015, and the statements of operations, comprehensive income, and cash flows for the three months ended March 31, 2015 and 2014, as applicable. The income / (loss) and cash flows for the periods ended March 31, 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.

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 April 2015, the Financial Accounting Standards Board (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 are 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 by retrospectively reclassifying 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 include amounts due from joint interest partners of approximately $130 million and $120 million, greenhouse gas emission credits of $67 million and $65 million, and deferred tax assets of $61 million each, at March 31, 2015 and December 31, 2014, respectively.

Accrued liabilities include accrued compensation-related costs of approximately $60 million and $95 million, interest payable of $97 million and $70 million and greenhouse gas liabilities of $75 million and $65 million, at March 31, 2015 and December 31, 2014, respectively. Other long-term liabilities include asset retirement obligations of $394 million and $397 million at March 31, 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 three-month period ended March 31, 2015. Interest paid totaled approximately $54 million and zero for the three months ended March 31, 2015 and 2014, respectively.

NOTE 4 INVENTORIES

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



	2015		2014
	(in millions)
Materials and supplies	$	67	$	66
Finished goods	4		5
Total	$	71	$	71

NOTE 5 DEBT

Debt consisted of the following:



	March 31, 2015			December 31, 2014
	(in millions)
Revolving Credit Facility	$	570		$	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	6,570			6,360

Less: Current maturities of long-term debt	(25		)	—

Less: Deferred financing costs	(66		)	(68		)

Total long-term debt, net	$	6,479		$	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 equal quarterly installments equal to 2.5% (10.00% per annum) of the principal amount of the Term Loan Facility beginning on March 31, 2016. As of March 31, 2015, we had $570 million outstanding under our Revolving Credit Facility with the ability to incur additional borrowings of up to $708 million under this facility after taking into account our cash balance.

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.

All obligations under the Credit Facilities are guaranteed jointly and severally by all of our wholly-owned material subsidiaries, and will be unsecured while we maintain our credit ratings at the minimum levels defined in the Credit Facilities. As of March 31, 2015, our corporate family rating from Moody's Investors Service was Ba2. 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), in a private placement. 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 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.

In connection with the private placement of the notes, we granted the initial purchasers certain registration rights under a registration rights agreement. In April 2015, we completed the exchange of tendered unregistered notes for registered notes.

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 percent 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 March 31, 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 $6.0 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 March 31, 2015, would result in an approximately $2 million change in annual interest expense.

As of March 31, 2015 and December 31, 2014, we had letters of credit in the aggregate amount of approximately $27 million and $25 million 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 March 31, 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 March 31, 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 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 $3 million of net derivative losses in net sales for the three months ended March 31, 2015.

In April 2015, we extended our existing hedging program to protect our capital plan by hedging 30,000 barrels per day of our expected fourth quarter 2015 oil production. For this tranche, we purchased Brent-based puts with a $60 per barrel floor and sold calls with a weighted average ceiling of $73.

In February 2015, we put into place derivatives to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program, we chose a combination of Brent-based collars (with a $55 per barrel floor and $72 ceiling) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, in part to pay for the cost of the options, we sold a $75 per barrel Brent-based call for 30,000 barrels per day of oil production for March through June of 2015. The initial value of these derivatives was not material.

In December 2014, we purchased put options, to hedge the risk associated with declining oil prices, for 100,000 barrels of crude oil production per day, effective on a monthly basis from January 1, 2015 through June 30, 2015. The strike price of the put options is $50 per barrel tied to the Brent oil index. Changes in the intrinsic value of the put option are deferred in other comprehensive income/(loss) as a cash flow hedge until the hedged transactions are recognized in the statement of operations. The initial intrinsic value and subsequent changes were not material.

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.

Going forward as an independent company, 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.

We entered into financial swap agreements in November 2012 for the sale of a portion of our natural gas production. These swap agreements hedged 50 MMcf of natural gas per day beginning in January 2013 through March 2014 and 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-month periods ended March 31, 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-month periods ended March 31, 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 2014 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 following table presents the gross and net fair values of our outstanding derivatives as of March 31, 2015 (in millions):



	Asset Derivatives			Liability Derivatives
March 31, 2015	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Other current assets	$	30	Accrued Liabilities	$	(4	)

Total gross and net fair value		$	30		$	(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 March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015
	Level 1		Level 2		Level 3		Collateral		Total
Assets:
Commodity derivative instruments, other current assets	$	—	$	30	$	—	$	—	$	30
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 three months ended March 31, 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. 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. At the end of the first quarter of 2015 we issued approximately 370,000 shares of common stock in connection with our employee stock purchase plan which began in January 2015. The effect of the employee stock purchase plan was anti-dilutive for the three months ended March 31, 2015.

The following table presents the calculation of basic and diluted EPS for the three-month periods ended March 31:



	2015			2014
	(in millions, except per-share amounts)
Basic EPS calculation
Net income / (loss)	$	(100	)	$	223
Net income / (loss) allocated to participating securities	—			(4		)
Net income / (loss) available to common stockholders	$	(100	)	$	219

Weighted-average common shares outstanding - basic	382.1			381.8
Basic EPS	$	(0.26	)	$	0.57

Diluted EPS calculation
Net income / (loss)	$	(100	)	$	223
Net income / (loss) allocated to participating securities	—			(4		)
Net income / (loss) available to common stockholders	$	(100	)	$	219

Weighted average common shares outstanding - basic	382.1			381.8
Dilutive effect of potentially dilutive securities	—			—
Weighted-average common shares outstanding - diluted	382.1			381.8
Diluted EPS	$	(0.26	)	$	0.57

NOTE 10 RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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



	Three months ended March 31,
		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	)		—
Total	$	1		$	2	$	1		$	2

We did not make any contributions to our defined benefit pension plans in either of the three-month periods ended March 31, 2015 and 2014.

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 months ended March 31, 2014 we had related party sales of approximately $1.1 billion.

Purchases from related parties reflect products purchased at market prices from Occidental’s subsidiaries and are used in our operations. These purchases were $21 million for the three months ended March 31, 2014 and were included in production costs. There were no significant related-party receivable or payable balances at March 31, 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 $35 million for the three months ended March 31, 2014 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, or 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.

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 primarily by adjusting our capital investments to be in line with current economic conditions, including adjusting the size and allocation of our capital program. The changes in the capital program have an impact on our production levels and cash flows.

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. In December 2014, we purchased put options with a $50 per barrel Brent strike price, measured monthly. This initial program covers

almost all of our oil production for the first six months of 2015. In February 2015, we put into place additional hedging instruments to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program we chose a combination of Brent-based collars (with a $55 per barrel floor and $72 ceiling) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, in part to pay for the cost of the options, we sold a $75 per barrel call for 30,000 barrels per day of oil production for March through June of 2015. In April 2015, we extended our existing hedging program to protect our capital investment plan by hedging 30,000 barrels per day of our expected fourth quarter 2015 oil production. For this tranche, we purchased Brent-based puts with a $60 per barrel floor and sold calls with a weighted average ceiling of $73. 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, which typically reflect 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 decreased in the first quarter of 2015 compared with the first quarter of 2014, reflecting a decline in the benchmarks as well as widening differentials.

The following table presents the average daily Brent, WTI and NYMEX prices for the three months ended March 31, 2015 and 2014:



	Three months ended March 31,
	2015		2014
Brent oil ($/Bbl)	$	55.17	$	107.90
WTI oil ($/Bbl)	$	48.63	$	98.68
NYMEX gas ($/Mcf)	$	3.06	$	4.66

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

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 are subject to contractual arrangements similar to production-sharing contracts and 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 and costs associated with contractually defined base production, (2) for our defined share of base production and (3) for our defined share of production in excess of base production for each period. We recover our share of capital and production costs, and generate returns, through our defined share of production from base and incremental production in (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.

Financial and Operating Results

For the first quarter of 2015, we had a net loss of $100 million and an adjusted net loss of $97 million. For the first quarter of 2014, we had net income and adjusted net income of $223 million. The table below reconciles net income / (loss) to adjusted net income / (loss):



	Three months ended March 31,
	2015			2014
	(in millions)
Net income / (loss)	$	(100	)	$	223
Rig terminations	2			—
Hedge related activity	3			—
Tax effect of pre-tax adjustments	(2		)	—
Adjusted net income / (loss)	$	(97	)	$	223

Our results of operations can include the effects of significant, unusual and 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).

The 2015 quarter reflected higher oil volumes and lower production costs, exploration expense and depreciation expense, more than offset by significantly lower realized oil, NGL, and gas prices and higher interest expense as a result of our capital structure which we assumed as an independent company.

Daily oil and gas production volumes averaged 166,000 barrels of oil equivalent (BOE) in the first quarter of 2015, compared with 154,000 BOE in the first quarter of 2014, an increase of 8%. Average oil production increased by 14%, or 13,000 barrels per day, to 108,000 barrels per day in the first quarter of 2015, reflecting our focus on high margin oil drilling. Our operations in the San Joaquin basin accounted for 5,000 barrels per day of the year-over-year oil production improvement reflecting our focus on steamfloods. Oil production from our other assets

increased by 8,000 barrels per day, which included the effect of lower prices on our Wilmington field contracts, which resemble a production sharing contract. NGL production decreased by 1,000 barrels per day and natural gas production was unchanged at 242 million cubic feet per day.

Realized crude oil prices decreased 55% to $46.44 per barrel for the first quarter of 2015 from $102.32 per barrel for the first quarter of 2014. The decrease reflected the drop in global oil prices and widening differentials to Brent related to California fundamentals, including certain first quarter 2015 refinery events. Realized NGL prices decreased 64% to $21.55 per barrel in the first quarter of 2015 from $60.39 per barrel in the first quarter of 2014. Natural gas realized prices decreased 41% in the first quarter of 2015 to $2.84 per thousand cubic feet (Mcf), compared with $4.78 per Mcf in the first quarter of 2014.

We drilled 55 wells in the first quarter of 2015, of which 2 were drilled for primary production, 45 were drilled for steamfloods primarily in the Kern Front field in the San Joaquin basin, 7 were focused on waterflood fields primarily in the Wilmington field in the Los Angeles basin and 1 was focused on unconventional reservoirs. Of the 45 wells drilled in the San Joaquin basin steamflood operations, 3 were exploration wells. Capital efficiency continued to improve in the first quarter of 2015 with average drilling costs coming in lower than 2014 levels.

The following table sets forth our average production volumes of oil, NGLs and natural gas per day for the three-month periods ended March 31, 2015 and 2014:



	Three months ended March 31,
	2015	2014
Oil (MBbl/d)
San Joaquin Basin	67	62
Los Angeles Basin	34	27
Ventura Basin	7	6
Sacramento Basin	—	—
Total	108	95

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

Natural gas (MMcf/d)
San Joaquin Basin	179	171
Los Angeles Basin	2	1
Ventura Basin	12	11
Sacramento Basin	49	59
Total	242	242

Total Production (MBoe/d)^(a)	166	154

_________________________


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

(a)

Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, for the three months ended March 31, 2015, the average prices of Brent oil and NYMEX natural gas were $55.17 per barrel and $3.06 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately 18 to 1.

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



	Three months ended March 31,
	2015		2014
Oil Prices ($ per Bbl)	$	46.44	$	102.32
NGLs Prices ($ per Bbl)	$	21.55	$	60.39
Gas Prices ($ per Mcf)	$	2.84	$	4.78

The following table presents our average realized prices as a percentage of Brent, WTI and NYMEX for the three-month periods ended March 31, 2015 and 2014:



	Three months ended March 31,
	2015		2014
Brent oil	84	%	95	%
WTI oil	95	%	104	%
NYMEX gas	93	%	103	%

Balance Sheet Analysis

The changes in our balance sheet since December 31, 2014 are discussed below:



	March 31, 2015		December 31, 2014
	(in millions)

Cash and cash equivalents	$	28	$	14
Trade receivables, net	$	241	$	308
Inventories	$	71	$	71
Other current assets	$	314	$	308
Property, plant and equipment, net	$	11,566	$	11,685
Other assets	$	44	$	43



Current maturities of long-term debt	$	25	$	—
Accounts payable	$	373	$	588
Accrued liabilities	$	337	$	334
Long-term debt, net	$	6,479	$	6,292
Deferred income taxes	$	1,986	$	2,055
Other long-term liabilities	$	548	$	549
Equity	$	2,516	$	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 due to lower product prices in the first quarter of 2015, compared to the fourth quarter of 2014. The decrease in property, plant and equipment, net 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 first scheduled quarterly payment on the term loan facility, on March 31, 2016. The decrease in accounts payable reflected the payments related to the high level of capital in the fourth quarter of 2014 and lower capital investment in the first quarter of 2015. 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 reflected the net loss for the period.

Statement of Operations Analysis

The following table presents the results of our operations, including the unusual and infrequent items discussed in the Financial and Operating Results section above:



	Three months ended March 31,
	2015			2014
	(in millions)
Oil and gas net sales (including related parties)	$	549		$	1,080
Other revenue	28			41
Production costs	(242		)	(256		)
General and administrative expenses	(76		)	(77		)
Depreciation, depletion and amortization	(253		)	(289		)
Taxes other than on income	(55		)	(52		)
Exploration expense	(17		)	(31		)
Interest and debt expense, net	(79		)	—
Other expenses	(24		)	(42		)
Income tax (expense) / benefit	69			(151		)
Net income / (loss)	$	(100	)	$	223

Adjusted EBITDAX⁽¹⁾	$	198		$	705

Effective tax rate	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, 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 one 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 March 31,
	2015			2014
	(in millions)
Net income / (loss)	$	(100	)	$	223
Interest expense	79			—
Income tax expense / (benefit)	(69		)	151
Depreciation, depletion and amortization	253			289
Exploration expense	17			31
Other	18			11
Adjusted EBITDAX	$	198		$	705

The following represents key metrics of our oil and gas operations, excluding certain corporate items, on a per BOE basis for the three months ended March 31:



	2015		2014
Production costs	$	16.20	$	18.43
Depreciation, depletion and amortization	$	16.49	$	20.47
Taxes other than on income	$	3.30	$	3.38

Three Months Ended March 31, 2015 vs. March 31, 2014

Net sales decreased 49%, or $531 million, for the three months ended March 31, 2015, compared to the same period of 2014, mainly due to a $540 million impact from lower oil prices, approximately $60 million from lower NGL prices and $40 million from lower natural gas prices. These decreases were partially offset by a $115 million impact from higher oil volumes. Average oil production increased 13,000 barrels per day, reflecting our focus on high margin oil drilling. NGL production decreased by 1,000 barrels per day and gas production remained flat.

Other revenue decreased 32%, or $13 million, for the three months ended March 31, 2015, compared to the same period of 2014. The decrease reflected lower third-party revenue from our Elk Hills power plant.

Production costs for the three months ended March 31, 2015 decreased 5%, or $14 million, to $242 million or$16.20 per BOE, compared to $256 million or $18.43 per BOE for the same period of 2014, mainly due to lower energy and gas costs, as well as improved well servicing efficiency. The decrease on a per unit basis was 12% period over period. Our overall cost containment program continued to have a positive effect on our production costs during the first quarter of 2015, compared to the same period of 2014.

General and administrative expenses for the three months ended March 31, 2015 were comparable to the same period of 2014, but on a per unit basis, they decreased by 8% from $5.54 per BOE in the first quarter of 2014 to $5.09 per BOE in the first quarter of 2015.

DD&A expense decreased 12%, or $36 million, for the three months ended March 31, 2015, compared to the same period of 2014. Of this decrease, approximately $55 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 $19 million attributable to higher volumes.

Taxes other than on income for the three months ended March 31, 2015 were comparable to the same period of 2014.

Exploration expense decreased 45%, or $14 million, for the three months ended March 31, 2015, compared to the same period of 2014, consistent with our reduced exploration activity.

Interest and debt expense, net for the first quarter of 2015 was $79 million, due to the debt we incurred in connection with the Spin-off in the fourth quarter of 2014.

Other expenses decreased 43%, or $18 million, for the three months ended March 31, 2015, compared to the same period of 2014, due to lower costs for our Elk Hills power plant.

Income tax (expense) / benefit showed a benefit of $69 million for the three months ended March 31, 2015, reflecting a pre-tax loss of $169 million for the quarter, compared to a provision of $151 million in the same period of 2014, reflecting pre-tax income of $374 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, dividends and any potential acquisitions for at least the next twelve months will be met by cash generated from operations, and borrowings when necessary. At March 31, 2015, we had approximately $708 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. While we believe the modified terms of our credit agreement will enable us to work through the current commodity price cycle, we have been exploring various alternatives 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 reflect the flexibility of our resource base, and may include a combination of asset monetizations, joint ventures and other opportunities.

Credit Facilities

Senior Notes

Cash Flow Analysis



	Three months ended March 31,
	2015			2014
	(in millions)
Net cash flows provided by operating activities	$	115		$	740
Net cash flows used in investing activities	$	(313	)	$	(501	)
Net cash flows provided / (used) by financing activities	$	212		$	(239	)
Adjusted EBITDAX ⁽¹⁾	$	198		$	705

_______________________________

(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:



	Three months ended March 31,
	2015			2014
	(in millions)
Net cash provided by operating activities	$	115		$	740
Interest expense	79			—
Cash exploration expenses	11			6
Changes in operating assets and liabilities	1			(71		)
Other, net	(8		)	30
Adjusted EBITDAX	$	198		$	705

Our net cash provided by operating activities decreased by $625 million to $115 million for the three months ended March 31, 2015. The decrease reflected lower revenue of approximately $545 million mainly due to lower product prices, $79 million of higher interest expense, and working capital changes of approximately $70 million, partially offset by lower cash income taxes of approximately $30 million and lower production and exploration costs of approximately $14 million each.

Our cash flow used in investing activities decreased by $188 million for the three months ended March 31, 2015 to $313 million, compared to the same period of 2014. The decrease reflected our lower capital investment program of $133 million in 2015 compared to $475 million in 2014. The 2015 investing activities also included approximately $170 million of 2014 capital accruals paid in 2015. The 2014 investing activities included $24 million of 2013 capital accruals paid in 2014.

Our net cash flow provided by financing activities increased by approximately $450 million for the three months ended March 31, 2015, compared to the same period of 2014. The change reflected net proceeds from the revolving credit facility of $210 million in 2015 and distributions to Occidental of $239 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 before capital 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, 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.

The table below sets forth our 2015 capital investments for the three months ended March 31, 2015:



	Conventional								Unconventional		Other		Total Capital Investments
	Primary		Waterflood		Steamflood		Total		Primary		Other		Total Capital Investments
Basin:
San Joaquin	$	30	$	5	$	37	$	72	$	17	$	—	$	89
Los Angeles	—		27		—		27		—		—		27
Ventura	3		—		—		3		—		—		3
Sacramento	—		—		—		—		—		—		—
Basin Total	33		32		37		102		17		—		119
Exploration and Other	—		—		—		—		—		14		14
Total	$	33	$	32	$	37	$	102	$	17	$	14	$	133

In addition, during this period of lower activity levels, we will deploy our resources to refine modern techniques to enhance the value and growth potential of the portion of our portfolio that will not be funded in 2015 and will continue to build our inventory of available projects. 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 April 2015, the Financial Accounting Standards Board (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 debt discounts. These rules are 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 by retrospectively reclassifying unamortized debt issuance costs of $68 million at December 31, 2014. The amount was previously reflected in other assets.

Safe Harbor Statement Regarding Outlook and Forward-Looking Information

The information in this document includes forward-looking statements. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. You can typically identify forward-looking statements by the use of forward-looking 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. Such statements may include statements regarding our future financial position, budgets, capital investments, projected production, projected costs, plans and objectives of management for future operations and possible future strategic transactions. 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. 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.

Any forward-looking statement in which we, or our management, express an expectation or belief as to future results, is made in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. The following are important factors that could cause actual results to differ materially from those anticipated: commodity price fluctuations; the effect of our debt on the impact of economic downturns and adverse business developments; sufficiency of our operating cash flow to fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water; risks of drilling; tax law changes; competition 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 months ended March 31, 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

In February 2015, we put into place hedging instruments to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program we chose a combination of Brent-based collars (with a $55 per barrel floor and $72 ceiling) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, in part to pay for the cost of the options, we sold a $75 per barrel call for 30,000 barrels per day of oil production in March through June of 2015. We will continue to be strategic and opportunistic with our hedging program in support of our capital investment plans. The hedges have been focused mainly on protecting our capital program in case of price deterioration.

Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For 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 March 31, 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 March 31, 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 March 31, 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 first 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



	4.1*	Guarantor Supplemental Indenture dated as of March 5, 2015, among California Resources Corporation, CRC Construction Services, LLC, certain other guarantors and Wells Fargo Bank, National Association, (filed as Exhibit 4.2 to the Registrant’s Registration Statement on Form S-4A filed on March 30, 2015, and incorporated herein by reference).

	10.1*	Assumption Agreement dated as of March 6, 2015, among CRC Construction Services, LLC and JP Morgan Chase Bank, N.A., as Administrative Agent for lenders, (filed as Exhibit 10.31 to the Registrant’s Registration Statement on Form S-4A filed on March 30, 2015, and incorporated herein by reference).

	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.

* - Incorporated herein by reference.

SIGNATURES

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



	CALIFORNIA RESOURCES CORPORATION



DATE:	May 7, 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.

California Resources Corp - FORM 10-Q - May 7, 2015

Attached files

California Resources Corp Reports