California Resources Corp - Quarter Report: 2016 June (Form 10-Q)

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission file number 001-36478

_____________________

California Resources Corporation

(Exact name of registrant as specified in its charter)



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

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

(888) 848-4754

(Registrant’s telephone number, including area code)

_____________________

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

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

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

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

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



Shares of common stock outstanding as of June 30, 2016	41,100,276

California Resources Corporation and Subsidiaries

Table of Contents



	Page
Part I

Item 1	Financial Statements (unaudited)	2
	Consolidated Condensed Balance Sheets	2
	Consolidated Condensed Statements of Operations	3
	Consolidated Condensed Statements of Comprehensive Loss	4
	Consolidated Condensed Statements of Cash Flows	5
	Notes to Consolidated Condensed Financial Statements	6
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	The Separation and Spin-off	17
	Business Environment and Industry Outlook	17
	Seasonality	18
	Income Taxes	19
	Operations	19
	Fixed and Variable Costs	19
	Financial and Operating Results	20
	Recent Developments	23
	Balance Sheet Analysis	23
	Statement of Operations Analysis	24
	Liquidity and Capital Resources	27
	Cash Flow Analysis	32
	2016 Capital Program	33
	Subsequent Events	33
	Lawsuits, Claims, Contingencies and Commitments	33
	Significant Accounting and Disclosure Changes	34
	Safe Harbor Statement Regarding Outlook and Forward-Looking Information	35
Item 3	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4	Controls and Procedures	37

Part II

Item 1	Legal Proceedings	38
Item 1A	Risk Factors	38
Item 5	Other Disclosures	38
Item 6	Exhibits	39

PART I FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

As of June 30, 2016 and December 31, 2015

(in millions)



	June 30,			December 31,
	2016			2015

CURRENT ASSETS

Cash and cash equivalents	$	2		$	12
Trade receivables, net	195			200
Inventories	62			58
Other current assets	127			227
Total current assets	386			497

PROPERTY, PLANT AND EQUIPMENT	20,887			20,996
Accumulated depreciation, depletion and amortization	(14,814		)	(14,684		)
Total property, plant and equipment	6,073			6,312

OTHER ASSETS	17			244

TOTAL ASSETS	$	6,476		$	7,053



CURRENT LIABILITIES

Current maturities of long-term debt	$	99		$	100
Accounts payable	187			257
Accrued liabilities	306			222
Current income taxes	—			26
Total current liabilities	592			605

LONG-TERM DEBT - PRINCIPAL AMOUNT	5,843			6,043

DEFERRED GAIN AND ISSUANCE COSTS, NET	456			491

DEFERRED INCOME TAXES	45			—

OTHER LONG-TERM LIABILITIES	585			830

EQUITY

Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at June 30, 2016 and December 31, 2015	—			—
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (June 30, 2016 - 41,100,276 and December 31, 2015 - 38,818,048)	—			—
Additional paid-in capital	4,837			4,782
Accumulated deficit	(5,873		)	(5,683		)
Accumulated other comprehensive loss	(9		)	(15		)

Total equity	(1,045		)	(916		)

TOTAL LIABILITIES AND EQUITY	$	6,476		$	7,053

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Operations

For the three and six months ended June 30, 2016 and 2015

(in millions, except per share amounts)



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
REVENUES AND OTHER
Oil and natural gas net sales	$	404		$	621		$	733		$	1,167
Net derivative losses	(118		)	(17		)	(143		)	(18		)
Other revenue	31			30			49			62
Total revenues and other	317			634			639			1,211

COSTS AND OTHER
Production costs	188			242			372			484
General and administrative expenses	61			85			128			161
Depreciation, depletion and amortization	138			251			285			504
Taxes other than on income	42			53			81			108
Exploration expense	5			7			10			24
Interest and debt expense, net	74			83			148			162
Other (income) expenses, net	(51		)	27			(117		)	51
Total costs and other	457			748			907			1,494

LOSS BEFORE INCOME TAXES	(140		)	(114		)	(268		)	(283		)
Income tax benefit	—			46			78			115
NET LOSS	$	(140	)	$	(68	)	$	(190	)	$	(168	)

Net loss per share of common stock
Basic	$	(3.51	)	$	(1.78	)	$	(4.85	)	$	(4.40	)
Diluted	$	(3.51	)	$	(1.78	)	$	(4.85	)	$	(4.40	)

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 Loss

For the three and six months ended June 30, 2016 and 2015

(in millions)



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Net loss	$	(140	)	$	(68	)	$	(190	)	$	(168	)
Other comprehensive income (loss) items:
Pension and postretirement losses ^(a)	—			(3		)	—			(3		)
Reclassification to income of realized losses on pension and postretirement ^(b)	3			5			6			5
Other comprehensive income (loss), net of tax	3			2			6			2
Comprehensive loss	$	(137	)	$	(66	)	$	(184	)	$	(166	)


(a)	No associated tax for the three and six months ended June 30, 2016. Net of tax of $2 million for the three and six months ended June 30, 2015. See Note 9, Retirement and Postretirement Benefit Plans, for additional information.


(b)	No associated tax for the three and six months ended June 30, 2016. Net of tax of $(3) million for the three and six months ended June 30, 2015, respectively. See Note 9, Retirement and Postretirement Benefit Plans, for additional information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Condensed Statements of Cash Flows

For the six months ended June 30, 2016 and 2015

(in millions)



	Six months ended June 30,
	2016			2015
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(190	)	$	(168	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	285			504
Deferred income tax expense (benefit)	(78		)	(115		)
Net derivative losses	143			18
Proceeds from settled derivatives	75			2
Other non-cash (gains) losses in income, net	(150		)	54
Dry hole expenses	—			7
Changes in operating assets and liabilities, net	(41		)	(70		)
Net cash provided by operating activities	44			232

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(26		)	(228		)
Changes in capital investment accruals	(11		)	(203		)
Asset divestitures	19			—
Acquisitions and other	—			(9		)
Net cash used by investing activities	(18		)	(440		)

CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from revolving credit facility	743			1,164
Repayments of revolving credit facility	(701		)	(934		)
Payments on long-term debt	(61		)	—
Debt repurchase and amendment costs	(20		)	—
Issuance of common stock	3			5
Cash dividends paid	—			(4		)
Net cash (used) provided by financing activities	(36		)	231
(Decrease) increase in cash and cash equivalents	(10		)	23
Cash and cash equivalents—beginning of period	12			14
Cash and cash equivalents—end of period	$	2		$	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, 2016

NOTE 1 THE SPIN-OFF AND BASIS OF PRESENTATION

The Separation and Spin-off

We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of California. We were incorporated in Delaware as a wholly-owned subsidiary of Occidental Petroleum Corporation (Occidental) on April 23, 2014, and remained a wholly-owned subsidiary of Occidental until our spin-off on November 30, 2014 (the Spin-off). Prior to the Spin-off, all material existing assets, operations and liabilities of Occidental's California business were consolidated under us. On November 30, 2014, Occidental distributed shares of our common stock on a pro rata basis to Occidental stockholders and we became an independent, publicly traded company. Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which it distributed to Occidental stockholders on March 24, 2016.

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

Basis of Presentation

In the opinion of our management, the accompanying financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our financial position as of June 30, 2016, and the statements of operations, comprehensive income, and cash flows for the three and six months ended June 30, 2016 and 2015, as applicable. We have eliminated all of our significant intercompany transactions and accounts. The loss and cash flows for the periods ended June 30, 2016 and 2015 are not necessarily indicative of the loss or cash flows you should expect for the full year.

Certain prior year amounts have been reclassified to conform to the 2016 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. This Form 10-Q should be read in conjunction with the consolidated and combined financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2015.


NOTE 2	ACCOUNTING AND DISCLOSURE CHANGES

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

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

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

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

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


NOTE 3	OTHER INFORMATION

Other current assets at June 30, 2016 and December 31, 2015, include amounts due from joint interest partners, net, of approximately $41 million and $42 million and deferred tax assets of $45 million and $59 million.

Other long-term liabilities include asset retirement obligations of $330 million and $343 million at June 30, 2016 and December 31, 2015, respectively.

Other revenue largely comprised sales of the portion of electricity generated by our power plant that is sold to third parties, and the related costs are included in other (income) expenses. In the quarter and six months ended June 30, 2016, other (income) expenses also included a $31 million of gain from the sale of non-core assets, as well as $44 million and $133 million, respectively, of gains related to the retirement of certain senior unsecured notes.

Fair Value of Financial Instruments

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

Supplemental Cash Flow Information

We did not make United States federal and state income tax payments during the six-month periods ended June 30, 2016 and 2015. Interest paid totaled approximately $180 million and $149 million for the six months ended June 30, 2016 and 2015, respectively.

Reverse Stock Split

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

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

NOTE 4 INVENTORIES

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



	June 30, 2016		December 31, 2015
	(in millions)
Materials and supplies	$	58	$	55
Finished goods	4		3
Total	$	62	$	58

NOTE 5 DEBT

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



	June 30, 2016			December 31, 2015
	(in millions)
Secured First Lien Bank Debt
Revolving Credit Facility	$	781		$	739
Term Loan Facility	939			1,000
Senior Secured Second Lien Notes
8% Notes Due 2022	2,250			2,250
Senior Unsecured Notes
5% Notes Due 2020	392			433
5 ½% Notes Due 2021	755			829
6% Notes Due 2024	825			892
Total Debt - Principal Amount	5,942			6,143
Less Current Maturities of Long-Term Debt	(99		)	(100		)
Long-Term Debt - Principal Amount	$	5,843		$	6,043

At June 30, 2016 deferred gain and issuance costs were $456 million net, consisting of $525 million of deferred gains offset by $69 million of deferred issuance costs. The December 31, 2015 deferred gain and issuance costs were $491 million net, consisting of $560 million of deferred gains offset by $69 million of deferred issuance costs.

Credit Facilities

We have a credit agreement effective through September 2019. The credit agreement provides for (i) a $939 million senior term loan facility (the Term Loan Facility) and (ii) a $1.6 billion senior revolving loan facility (the Revolving Credit Facility and, together with the Term Loan Facility, the Credit Facilities). All borrowings under the Credit Facilities are subject to certain customary conditions. We amended the Credit Facilities effective as of February 2016, to change certain of our financial and other covenants. We further amended these agreements in April 2016 to facilitate certain types of deleveraging transactions. Borrowings under our Credit Facilities are subject to a borrowing base which was reaffirmed at $2.3 billion as of May 2016. We have granted our lenders a first-priority lien in a substantial majority of our upstream assets.

The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit. As of June 30, 2016 and December 31, 2015, we had outstanding borrowings under our Revolving Credit Facility of $781 million and $739 million, respectively, and outstanding borrowings of $939 million and $1 billion under the Term Loan Facility, respectively. We made two scheduled $25 million quarterly payments on the Term Loan Facility during the quarters ended March 31, 2016 and June 30, 2016 and an $11 million payment from the proceeds of non-core asset sales.

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, while our total leverage ratio exceeds 3.00:1.00, on our borrowing base utilization and will vary from (a) in the case of LIBOR loans, 2.50% to 3.50% and (b) in the case of ABR loans, 1.50% to 2.50%. The unused portion of the Revolving Credit Facility commitments, as limited by the borrowing base, is subject to a commitment fee equal to 0.50% per annum. We also pay customary fees and expenses under the Credit Facilities. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly.

Our financial performance covenants through December 31, 2016 comprise an obligation to achieve (i) a cumulative minimum EBITDAX during 2016 of $55 million through the first quarter, $130 million through the second quarter, $190 million through the third quarter and $250 million through the fourth quarter and (ii) a trailing four-quarter minimum interest coverage ratio of 2.00:1.00 as of the end of the first quarter of 2016, 1.50:1.00 as of the end of the second quarter, 1.25:1.00 as of the end of the third quarter, 0.70:1.00 as of the end of the fourth quarter and 2.00:1.00 thereafter as of each quarter end. Starting with the end of the first quarter of 2017, we will be subject to a trailing four-quarter maximum first lien senior secured leverage ratio of 2.25:1.00. Oil prices would need to increase significantly in order for us to comply with our covenants at the end of the first quarter of 2017. Unless prices for our products increase significantly, we expect we will need to amend the covenants under our credit facilities before the end of March 2017 in order to remain compliant. We can give no assurances that our lenders will amend our covenants. If we were to breach any of our covenants, our lenders would be permitted to accelerate the principal amount due under the Credit Facilities and foreclose on the assets securing them. If payment were accelerated under our Credit Facilities, it would result in a default under our outstanding notes and permit acceleration and foreclosure on the assets securing the secured notes.

Except as otherwise agreed with our lenders for specific transactions, our Credit Facilities require us to apply 100% of the proceeds from asset sales to repay loans outstanding under the Credit Facilities, except that we are permitted to use up to 40% of proceeds from non-borrowing base asset monetizations to repurchase our notes to the extent available at a significant minimum discount to par, as specified in the facilities. In addition, subject to compliance with our indentures, we may incur additional indebtedness to repurchase our notes to the extent available at a specified minimum discount to par, as follows: (i) up to $1 billion, which may be secured by liens that are junior to the liens securing our Credit Facilities, provided that at least 60% of the proceeds from such new debt is used first to repay loans outstanding under the Term Loan Facility, and (ii) up to $200 million, which may be secured by first-priority liens on our non-borrowing base properties. The Credit Facilities also permit us to incur up to an additional $50 million of non-Credit Facility indebtedness, which, subject to compliance with our indentures, may be secured; and the proceeds of which must be applied to repay the Term Loan Facility. We must apply cash on hand in excess of $150 million to repay amounts outstanding under our Revolving Credit Facility. Further, we are restricted from (i) paying dividends or making other distributions to common stockholders and (ii) making capital investments exceeding $100 million during 2016.

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

All obligations under the Credit Facilities are guaranteed jointly and severally by all of our material wholly-owned subsidiaries. The assets and liabilities of subsidiaries not guaranteeing the debt are de minimis.

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

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

See Note 11 - Subsequent Events for discussion of our recently announced tender offer, proposed syndicated loan facility and proposed amendment to our Credit Facilities.

Senior Notes

In October 2014, we issued $5.00 billion in aggregate principal amount of our senior unsecured notes, including $1.00 billion of 5% senior unsecured notes due January 15, 2020 (the 2020 notes), $1.75 billion of 5 ½% senior unsecured notes due September 15, 2021 (the 2021 notes) and $2.25 billion of 6% senior unsecured notes due November 15, 2024 (the 2024 notes and together with the 2020 notes and the 2021 notes, the unsecured notes). The unsecured notes were issued at par and are fully and unconditionally guaranteed on a senior unsecured basis by all of our material subsidiaries. We used the net proceeds from the issuance of the unsecured notes to make a $4.95 billion cash distribution to Occidental in October 2014.

In December 2015, we exchanged $534 million, $921 million and $1,358 million in aggregate principal amount of the 2020 notes, the 2021 notes, and the 2024 notes, respectively, for $2.25 billion in aggregate principal amount of newly issued 8% senior secured second lien notes due December 15, 2022 (the 2022 notes). We recorded a deferred gain of approximately $560 million on the debt exchange, which will be amortized using the effective interest rate method over the term of the 2022 notes. Additionally, we incurred approximately $28 million in third-party costs which were fully expensed in 2015. The second lien notes are secured on a second-priority basis, subject to the terms of an intercreditor agreement and collateral trust agreement by a lien on the same collateral used to secure our obligations under our Credit Facilities.

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

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

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

Other

We estimate the fair value of fixed-rate debt, which is classified as Level 1, based on prices from known market transactions for our instruments. The estimated fair value of our debt at June 30, 2016 and December 31, 2015, including the fair value of the variable rate portion, was approximately $4.3 billion and $3.6 billion, respectively, compared to a carrying value of approximately $5.9 billion and $6.1 billion. A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on June 30, 2016, would result in a $2.1 million change in annual interest expense.

As of June 30, 2016 and December 31, 2015, we had letters of credit in the aggregate amount of approximately $129 million and $70 million (including $120 million and $49 million under the Revolving Credit Facility), respectively, which were issued to support ordinary course marketing, insurance, regulatory and other matters.

NOTE 6 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We, or certain of our subsidiaries, are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

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

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserves balances at June 30, 2016 and December 31, 2015 were not material to our balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.

We, our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with the Spin-off, purchases and other transactions that they have entered into with us. These indemnities include indemnities made to Occidental against certain tax-related liabilities that may be incurred by Occidental relating to the Spin-off and liabilities related to operation of our business while it was still owned by Occidental. As of June 30, 2016, we are not aware of material indemnity claims pending or threatened against the Company.

NOTE 7 DERIVATIVES

General

We use a variety of derivative instruments intended to improve the effective realized prices for oil and gas and protect our capital program in case of price deterioration. Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. We apply hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, we recognize any fair value gains or losses, over the remaining term of the hedge instrument, in earnings in the current period.

As of June 30, 2016, we did not have any derivatives designated as hedges. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not necessarily accounted for as cash flow or fair value hedges. As part of our hedging program, we entered into a number of derivative transactions that resulted in the following Brent-based crude oil and NYMEX-based gas hedge positions as of June 30, 2016:



	2016				2017		2018
	Q3		Q4		Q1 - Q4		Q1 - Q4
Crude Oil
Calls:
Barrels per day	19,000		25,000		12,200		23,300
Weighted-average price per barrel	$	55.08	$	53.62	$	55.91	$	57.99

Puts:
Barrels per day	28,000		3,000		4,300		—
Weighted-average price per barrel	$	50.65	$	50.00	$	50.00	$	—

Swaps:
Barrels per day	1,000		29,000		—		—
Weighted-average price per barrel	$	61.25	$	49.43	$	—	$	—

Gas
Swaps:
Millions British Thermal Units (MMBTU) per day	330		5,500		—		—
Weighted-average price per MMBTU	$	3.13	$	3.50	$	—	$	—

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

During the three months ended June 30, 2016 and subsequent to that period, we purchased derivative assets that partially reduced our call exposure on 2017 production to a total of 10,500 barrels per day with a weighted-average ceiling of $56.07 and our call exposure on our 2018 production to a total of 21,500 barrels per day with a weighted-average ceiling of $58.21.

Fair Value of Derivatives

Our commodity derivatives are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are all classified as Level 2 in the required fair value hierarchy for the periods presented. The following table presents the fair values (at gross and net) of our outstanding derivatives as of June 30, 2016 and December 31, 2015 (in millions):



	June 30, 2016
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheet			Net Fair Value Presented in the Balance Sheet
Assets
Commodity Contracts	Other current assets	$	66		$	(48	)	$	18

Liabilities
Commodity Contracts	Accrued liabilities	(52		)	26			(26		)
Commodity Contracts	Other long-term liabilities	(95		)	22			(73		)
Total derivatives		$	(81	)	$	—		$	(81	)



	December 31, 2015
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
Assets
Commodity Contracts	Other current assets	$	87		$	—	$	87

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

NOTE 8 EARNINGS PER SHARE

We compute earnings per share (EPS) using the two-class method required for participating securities. Undistributed earnings allocated to participating securities are subtracted from net income in determining net income attributable to common stockholders. 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 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. The effect of the stock options granted in August 2015 and December 2014 was anti-dilutive for the periods presented.

For the three and six months ended June 30, 2016, we issued approximately 86,000 shares and 184,000 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 both periods.

The following table presents the calculation of basic and diluted EPS for the three- and six-month periods ended June 30, 2016 and 2015:



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(in millions, except per-share amounts)
Basic EPS calculation
Net loss	$	(140	)	$	(68	)	$	(190	)	$	(168	)
Net loss allocated to participating securities	—			—			—			—
Net loss available to common stockholders	$	(140	)	$	(68	)	$	(190	)	$	(168	)

Weighted-average common shares outstanding - basic	39.9			38.3			39.2			38.2
Basic EPS	$	(3.51	)	$	(1.78	)	$	(4.85	)	$	(4.40	)

Diluted EPS calculation
Net loss	$	(140	)	$	(68	)	$	(190	)	$	(168	)
Net loss allocated to participating securities	—			—			—			—
Net loss available to common stockholders	$	(140	)	$	(68	)	$	(190	)	$	(168	)

Weighted-average common shares outstanding - basic	39.9			38.3			39.2			38.2
Dilutive effect of potentially dilutive securities	—			—			—			—
Weighted-average common shares outstanding - diluted	39.9			38.3			39.2			38.2
Diluted EPS	$	(3.51	)	$	(1.78	)	$	(4.85	)	$	(4.40	)

NOTE 9 RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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



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



	Six months ended June 30,
	2016					2015
	Pension Benefit			Postretirement Benefit		Pension Benefit			Postretirement Benefit
	(in millions)
Service cost	$	1		$	2	$	2		$	2
Interest cost	1			2		2			2
Expected return on plan assets	(2		)	—		(2		)	—
Recognized actuarial loss	1			—		1			—
Settlement loss	6			—		8			—
Total	$	7		$	4	$	11		$	4

We contributed $1 million and $3 million to our defined benefit pension plans during the three months ended June 30, 2016 and 2015, respectively. We contributed $6 million and $3 million to our defined benefit pension plans during the six months ended June 30, 2016 and 2015, respectively. We expect to satisfy minimum funding requirements with contributions of $2 million to our defined benefit pension plans during the remainder of 2016. The 2016 and 2015 settlements were associated with early retirements.

NOTE 10 INCOME TAXES

As a result of the debt exchange in December 2015, we generated cancellation of debt income of $1.39 billion for tax purposes, which represented the excess of the face value of the surrendered notes over the fair value of the newly issued notes at the time of the exchange. The tax gain exceeded our operating loss for the year. We reported the related $336 million of federal and state taxes in current and other long-term liabilities in the accompanying balance sheet at December 31, 2015. During the first quarter of 2016, we reclassified this amount to deferred taxes to reflect the reduction in the tax basis of our assets resulting from the exclusion of the $1.39 billion in cancellation of debt income from our 2015 taxable income. We also recorded a deferred income tax benefit of approximately $78 million to reflect a change in the valuation allowance on our deferred tax assets. During the second quarter of 2016, we recorded a full valuation allowance against the deferred tax assets that resulted from current period tax losses.

NOTE 11 SUBSEQUENT EVENTS

We announced the commencement on August 1 of our offers to purchase (Tender Offers) up to the combined aggregate principal amount of our notes that can be purchased with $525 million in cash at stated discounts to par. The offers are conditioned on, among other things, (i) entry into, and effectiveness of, an amendment to our Credit Facilities and the availability of sufficient funds from the Credit Facilities necessary to consummate the Tender Offers and (ii) a sufficient aggregate principal amount of our notes being validly tendered (and not validly withdrawn) to result in a minimum of $500 million in aggregate principal amount of our notes being accepted for purchase. Notes accepted for purchase by us would receive base consideration of $510 per $1,000 in principal amount of our 2020 notes accepted, $490 per $1,000 in principal amount of our 2021 notes accepted, $460 per $1,000 in principal amount of our 2024 notes accepted and $625 per $1,000 in principal amount of our 2022 notes accepted, and an early participation premium of $50 per $1,000, plus accrued and unpaid interest. We will not accept more than $200 million in aggregate principal amount of our 2022 notes under the Tender Offers.

We are concurrently seeking to amend our Credit Facilities to permit the consummation of these offers and the incurrence of a new syndicated loan facility. We also expect that the amendment will, among other things, reduce the Revolving Credit Facility commitments from $1.6 billion to $1.4 billion, provide covenant relief until the end of the first quarter of 2018 and grant a lien on our substantially all of our assets not currently pledged to secure the Credit Facilities.

We are seeking an aggregate principal amount of at least $700 million under the syndicated facility, which will be secured by a first priority lien on the same collateral as used to secure the Credit Facilities, but with “second out” collateral recovery pursuant to an intercreditor agreement between the Credit Facility lenders and the syndicated facility lenders. We expect 25% of the proceeds from the syndicated facility to be used to pay down the Term Loan Facility and the balance to be used to pay down the Revolving Loan Facility.

We will consummate the Credit Facility amendment, the syndicated facility and the Tender Offers, if we are able to successfully complete the marketing of the syndicated facility on satisfactory pricing terms and conditions and achieve a successful outcome in the Tender Offers.

Our lenders, under the Credit Facilities or under the syndicated facility, may impose additional restrictions that we have not described. Also, we may otherwise alter the terms of these transactions in response to market conditions.


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

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 the spin-off on November 30, 2014 (the Spin-off). Prior to the Spin-off, all material existing assets, operations and liabilities of Occidental's California business were consolidated under us. On November 30, 2014, Occidental distributed shares of our common stock on a pro rata basis to Occidental stockholders and we became an independent, publicly traded company. Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which it distributed to Occidental stockholders on March 24, 2016.

Business Environment and Industry Outlook

Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly, generally as a result of changes in supply and demand and other market-related uncertainties. These and other factors make it impossible to predict realized prices reliably. Much of the global exploration and production industry is challenged at current price levels, putting pressure on the industry's ability to generate positive cash flow and access capital. Average oil prices continued the decline that began in the last half of 2014 into the first quarter of 2016. While global oil prices improved modestly in the second quarter of 2016 and started to trade in a narrower range, they were still lower in the second quarter and first half of 2016 compared to the same periods in 2015.

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

Natural gas prices remained lower in the second quarter and first half of 2016 than comparable periods in 2015. However, Henry Hub futures prices for the second half of the year started to rebound strongly on lower production, higher demand and warmer weather forecasts. California natural gas differentials for the second half of the year also started to improve primarily due to storage-related issues in the state.

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



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Brent oil ($/Bbl)	$	46.97	$	63.50	$	41.03	$	59.33
WTI oil ($/Bbl)	$	45.59	$	57.94	$	39.52	$	53.29
NYMEX gas ($/Mcf)	$	1.97	$	2.74	$	2.02	$	2.90

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

We currently sell all of our crude oil into the California refining markets, which we believe have offered relatively favorable pricing compared to other U.S. regions for similar grades. California imports over 60% of its oil and approximately 90% of its natural gas. A vast majority of the oil is imported via supertanker, with a negligible amount arriving by rail. As a result, California refiners have typically purchased crude oil at international waterborne-based prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will continue contributing to higher realizations than most other U.S. oil markets for comparable grades. Beginning in late 2015, the U.S. federal government allowed the export of crude oil. As a result, we are opportunistically pursuing newly opened export markets for our crude oil production to improve our margins.

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

Our earnings are also affected by the performance of our processing and power generation assets. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Additionally, we provide part of the electricity output from our Elk Hills power plant to reduce Elk Hills field operating costs and increase reliability.

Natural gas prices and differentials are strongly affected by local supply and demand fundamentals, as well as availability of transportation capacity from producing areas. Due to much lower levels of natural gas production compared to our oil production, the changes in natural gas prices have a lower impact on our operating results.

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

We will continue to be strategic and opportunistic in implementing our hedging program as market conditions permit. Our objective is to protect against the cyclical nature of commodity prices to protect our cash flows, margins and capital investment program and improve our ability to comply with our credit facility covenants in case of further price deterioration. We have crude oil hedges in place for the remainder of 2016 consisting of Brent-based options and swaps, representing average production of 30,500 barrels of oil per day at a weighted-average floor price of $50.21 per barrel. We also have hedges in place for 2017 average production of 4,300 barrels of oil per day at a weighted-average price of $50.00. In addition, we entered into calls on a small portion of our 2017 and 2018 production as part of placing the 2016 hedges earlier in the year.

We have natural gas hedges in place for the third and fourth quarters of 2016 consisting of swaps representing average production of 2,900 Million British Thermal Units (MMBTU) per day at a weighted-average floor price of $3.48 per MMBTU. We also have forward contracts for 2017 average production of 6,200 MMBTU per day at a weighted-average floor price of $3.53.

We can give no assurances that these hedges will be adequate to accomplish our hedging program objectives. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not necessarily accounted for as cash-flow or fair-value hedges.

We respond to economic conditions by adjusting the size and allocation of our capital program, aligning the size of our workforce with the level of activity, continuing to improve efficiencies and cost savings and working with our suppliers and service providers to adjust the cost of goods and services to reflect current market pricing. The reductions in our capital program will negatively impact our production levels in the near term and sustained low-price periods may materially affect the quantities of oil and gas reserves we can economically produce over the longer term.

Seasonality

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

Income Taxes

As a result of the debt exchange we completed in December 2015, we generated cancellation of debt income of $1.39 billion for tax purposes, which represented the excess of the face value of the surrendered notes over the fair value of the newly issued notes at the time of the exchange. The tax gain exceeded our operating loss for the year. We reported the related $336 million of federal and state taxes in current and other long-term liabilities in the accompanying balance sheet at December 31, 2015. During the first quarter of 2016, we reclassified this amount to deferred taxes to reflect the reduction in the tax basis of our assets resulting from the exclusion of the $1.39 billion in cancellation of debt income from our 2015 taxable income. We also recorded a deferred income tax benefit of approximately $78 million to reflect a change in the valuation allowance on our deferred tax assets. During the second quarter of 2016, we recorded a full valuation allowance against the deferred tax assets that resulted from current period tax losses.

Operations

We conduct our operations through fee interests, land leases and other contractual arrangements. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.4 million net acres, approximately 60% of which we hold in fee. Our oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. We also own a network of strategically placed infrastructure that is integrated with our operations, including gas plants, oil and gas gathering systems, a power plant and other related assets, to maximize the value generated from our production.

Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and production costs. We record a share of production and reserves to recover such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (1) to recover our partners’ share of capital and production costs that we incur on their behalf, (2) for our share of contractually defined base production and (3) for our share of production in excess of contractually defined base production for each period. We realize our share of capital and production costs, and generate returns, through our defined share of production from (2) and (3) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, however, our net economic benefit is greater when product prices are higher. The contracts represented slightly less than 20% of our production for the quarter ended June 30, 2016.

Fixed and Variable Costs

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

Financial and Operating Results

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



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(in millions)
Net loss	$	(140	)	$	(68	)	$	(190	)	$	(168	)
Non-cash, unusual and infrequent items:
Non-cash derivative losses	137			17			218			20
Severance and other employee-related costs	4			10			18			10
Plant turnaround and other costs	2			1			9			3
Gain on retirement of notes	(44		)	—			(133		)	—
Gain from asset divestitures	(31		)	—			(31		)	—
Valuation allowance for deferred tax assets ^(a)	—			—			(63		)	—
Tax effects of these items	—			(11		)	—			(13		)
Adjusted net loss	$	(72	)	$	(51	)	$	(172	)	$	(148	)

Net loss per diluted share	$	(3.51	)	$	(1.78	)	$	(4.85	)	$	(4.40	)
Adjusted net loss per diluted share	$	(1.80	)	$	(1.33	)	$	(4.39	)	$	(3.87	)

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

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



	Three months ended June 30,					Six months ended June 30,
	2016			2015		2016			2015
	(in millions)
Non-cash derivative losses	$	137		$	17	$	218		$	20
Proceeds from settled derivatives	(19		)	—		(75		)	(2		)
Net derivative losses	$	118		$	17	$	143		$	18

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



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(in millions)
General and administrative expenses	$	61		$	85		$	128		$	161
Severance and other employee-related costs	(4		)	(10		)	(18		)	(10		)
Adjusted general and administrative expenses	$	57		$	75		$	110		$	151

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

The results for the three months ended June 30, 2016, compared to the same period in 2015, reflected lower production costs, general and administrative expenses, ad valorem expense, depreciation, depletion and amortization expense (DD&A), exploration expense and interest expense, as well as gains on the retirement of notes and sale of non-core assets, more than offset by lower oil and gas realized prices and lower volumes for all products. The overall decrease in our realized oil prices included the effect of the cash received from our hedging program. Our adjusted net loss for the three months ended June 30, 2016 excluded $137 million of non-cash derivative losses on outstanding positions at June 30, 2016, $44 million of gains on the retirement of notes, a $31 million gain on the sale of assets and $6 million of other non-recurring charges. Our adjusted net loss for the three months ended June 30, 2015 excluded $17 million of after-tax non-recurring adjustments.

Daily oil and gas production volumes averaged 140,000 barrels of oil equivalent (Boe) for the second quarter of 2016, compared with 161,000 Boe for the second quarter of 2015, representing a 13% year-over-year decline rate. Average oil production decreased by 13% or 14,000 barrels per day to 90,000 barrels per day for the three months ended June 30, 2016, compared to the same period of the prior year. NGL production decreased by 11% to 16,000 barrels per day. Natural gas production decreased by 14% to 202 million cubic feet (MMcf) per day. The second quarter production declines reflected our decision to withhold development capital and selectively defer workover and downhole maintenance activity for the first half of the year. We began increasing our activity levels gradually towards the end of the quarter in response to the improved price environment. Additionally, temporary California pipeline disruptions negatively impacted our ability to sell all of the oil we produced for the second quarter of 2016, some of which we held in inventory at the end of the quarter. As a result, the actual second quarter production was slightly higher than the reported volumes, which represent sales. We expect this inventory to be sold in the third quarter of 2016 and reported as production at that time.

Realized crude oil prices, including the effect of cash received from settled hedges, decreased 23% to $43.70 per barrel for the second quarter of 2016 from $56.73 per barrel for the second quarter of 2015. The decrease in realized oil prices reflected the drop in global oil indexes. Hedges in the second quarter of 2016 contributed $2.29 per barrel to the realized crude oil price, compared with no effect in the second quarter of 2015. Realized NGL prices increased 10% to $22.54 per barrel for the second quarter of 2016 from $20.47 per barrel for the second quarter of 2015. Realized natural gas prices decreased 33% for the second quarter of 2016 to $1.66 per thousand cubic feet (Mcf), compared with $2.49 per Mcf for the same period of 2015.

The first six months of 2016, compared to the same period in 2015, reflected lower production costs, general and administrative expenses, ad valorem expense, DD&A, exploration expense and interest expense, as well as gains on the retirement of notes and sale of non-core assets, more than offset by lower oil, NGL and gas realized prices and volumes. The overall decrease in our realized oil prices included the effect of the cash received from our hedging program. Our adjusted net loss for the six months ended June 30, 2016 excluded $218 million of non-cash derivative losses on outstanding positions at June 30, 2016, $133 million of gains on the retirement of notes, a $63 million deferred tax valuation allowance reduction, a $31 million gain on the sale of assets and $27 million of other non-recurring charges. Our adjusted net loss for the six months ended June 30, 2015 excluded $20 million of after-tax non-recurring adjustments.

For the first six months of 2016, daily production averaged 144,000 Boe, compared with 163,000 for the first six months of 2015, representing a 12% year-over-year reduction. Average oil production decreased 12,000 barrels per day, or by 11%, to 94,000 barrels per day for 2016. NGL production decreased by 6% to 17,000 barrels per day and natural gas production decreased by 16% to 199 MMcf per day.

Realized crude oil prices, including the effect of cash received from settled hedges, decreased 23% to $39.90 per barrel for the first six months of 2016 from $51.51 per barrel for the first six months of 2015. The decrease in realized oil prices reflected the reduction in global oil indexes. Hedges for the first six months of 2016 contributed $4.38 per barrel to the realized crude oil price, compared with $0.03 for the first six months of 2015. Realized NGL prices decreased 8% to $19.35 per barrel for the first six months of 2016 from $21.00 per barrel for the first six months of 2015. Realized natural gas prices decreased 31% to $1.85 per Mcf in the first six months of 2016, compared with $2.67 per Mcf for the same period of 2015.

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, 2016 and 2015:



	Three months ended June 30,		Six months ended June 30,
	2016	2015	2016	2015
Oil (MBbl/d)
San Joaquin Basin	56	67	58	67
Los Angeles Basin	29	31	31	33
Ventura Basin	5	6	5	6
Sacramento Basin	—	—	—	—
Total	90	104	94	106

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

Natural gas (MMcf/d)
San Joaquin Basin	152	175	149	177
Los Angeles Basin	4	2	3	2
Ventura Basin	9	11	9	12
Sacramento Basin	37	46	38	47
Total	202	234	199	238

Total Production (MBoe/d)^(a)	140	161	144	163

_______________________


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, 2016, the average prices of Brent oil and NYMEX natural gas were $41.03 per barrel and $2.02 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,
	2016		2015		2016		2015
Oil prices with hedge ($ per Bbl)	$	43.70	$	56.73	$	39.90	$	51.51

Oil prices without hedge ($ per Bbl)	$	41.41	$	56.73	$	35.52	$	51.48
NGLs prices ($ per Bbl)	$	22.54	$	20.47	$	19.35	$	21.00
Gas prices ($ per Mcf)	$	1.66	$	2.49	$	1.85	$	2.67

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, 2016 and 2015:



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Oil with hedge as a percentage of Brent	93	%	89	%	97	%	87	%

Oil without hedge as a percentage of Brent	88	%	89	%	87	%	87	%
Oil without hedge as a percentage of WTI	91	%	98	%	90	%	97	%
Gas with hedge as a percentage of NYMEX	84	%	91	%	92	%	92	%

Recent Developments

Our stockholders approved a reverse stock split at the Company's annual stockholders’ meeting May 4, 2016. Following this approval, our board of directors authorized a reverse split using a ratio of one share of common stock

for every ten shares then outstanding. The split occurred on May 31, 2016 with trading on a post-split basis commencing the following day. Share and per share amounts included in this report have been restated to reflect this reverse stock split.

Balance Sheet Analysis

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



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

Cash and cash equivalents	$	2	$	12
Trade receivables, net	$	195	$	200
Inventories	$	62	$	58
Other current assets	$	127	$	227
Property, plant and equipment, net	$	6,073	$	6,312
Other assets	$	17	$	244



Current maturities of long-term debt	$	99		$	100
Accounts payable	$	187		$	257
Accrued liabilities	$	306		$	222
Current income taxes	$	—		$	26
Long-term debt - principal amount	$	5,843		$	6,043
Deferred gain and issuance costs, net	$	456		$	491
Deferred income taxes	$	45		$	—
Other long-term liabilities	$	585		$	830
Equity	$	(1,045	)	$	(916	)

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

The decrease in other current assets was mainly due to a reduction in the value of our derivatives and lower deferred tax assets resulting from the reclassification of our tax liabilities to deferred taxes. The decrease in property, plant and equipment reflected DD&A for the period, partially offset by capital investments. The decrease in other assets was mainly due to lower deferred tax assets.

The decrease in accounts payable reflected lower capital investments and production costs in 2016. The increase in accrued liabilities was primarily due to the deferral of gains related to sales of greenhouse gas allowances and the change in value of derivative liabilities, partially offset by the effect of employee bonus payments in the first quarter of 2016. The decrease in equity primarily reflected the net loss for the six-month period in 2016, partially offset by the common stock issued in the second quarter debt exchange.

Current income taxes and other long-term liabilities as of December 31, 2015 included $336 million in tax liabilities that have been reclassified to deferred taxes to reflect a reduction in the tax basis of our assets as a result of excluding the 2015 $1.39 billion of cancellation of debt income for tax purposes.

Statement of Operations Analysis

The following table presents the results of our operations:



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(in millions)
Oil and gas net sales	$	404		$	621		$	733		$	1,167
Net derivative losses	(118		)	(17		)	(143		)	(18		)
Other revenue	31			30			49			62
Production costs	(188		)	(242		)	(372		)	(484		)
General and administrative expenses	(61		)	(85		)	(128		)	(161		)
Depreciation, depletion and amortization	(138		)	(251		)	(285		)	(504		)
Taxes other than on income	(42		)	(53		)	(81		)	(108		)
Exploration expense	(5		)	(7		)	(10		)	(24		)
Interest and debt expense, net	(74		)	(83		)	(148		)	(162		)
Other income (expenses), net	51			(27		)	117			(51		)
Income tax benefit	—			46			78			115
Net loss	$	(140	)	$	(68	)	$	(190	)	$	(168	)

Adjusted net loss^(a)	$	(72	)	$	(51	)	$	(172	)	$	(148	)
Adjusted EBITDAX^(b)	$	160		$	270		$	284		$	468

Effective tax rate	—		%	40		%	29		%	41		%

________________________


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

(b)

We define adjusted EBITDAX consistent with our Credit Facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other non-cash, unusual and infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and investment community. The amounts included in the calculation of adjusted EBITDAX were computed in accordance with GAAP. This measure is a material component of our financial covenants under our 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,
	2016			2015			2016			2015
	(in millions)
Net loss	$	(140	)	$	(68	)	$	(190	)	$	(168	)
Interest and debt expense	74			83			148			162
Income tax benefit	—			(46		)	(78		)	(115		)
Depreciation, depletion and amortization	138			251			285			504
Exploration expense	5			7			10			24
Adjusted income items^(a)	68			28			81			33
Other non-cash items	15			15			28			28
Adjusted EBITDAX	$	160		$	270		$	284		$	468


(a)	For 2016, includes non-cash losses on outstanding hedges, severance and other employee-related costs, plant turnaround costs, gain on retirement of notes and gain from the sale of assets. For 2015, includes non-cash losses on outstanding hedges, severance and other employee-related costs and rig termination costs.

The following presents costs included in 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,
	2016		2015		2016		2015
Production costs	$	14.76	$	16.59	$	14.21	$	16.39
General and administrative expenses	$	0.71	$	1.03	$	0.73	$	0.95
Depreciation, depletion and amortization	$	10.21	$	16.72	$	10.28	$	16.60
Taxes other than on income	$	2.75	$	3.24	$	2.71	$	3.27

Three months ended June 30, 2016 vs. 2015

Oil and gas net sales decreased 35%, or $217 million, for the three months ended June 30, 2016, compared to the same period of 2015, due to an approximately $193 million negative impact from lower oil prices and volumes, $22 million from lower natural gas prices and volumes and $2 million from lower NGL prices. The lower realized oil prices resulted from a significant decrease in benchmark indexes. Our realized oil prices in 2016 included $19 million of cash generated from our hedging program. Daily oil and gas production volumes averaged 140,000 Boe in the second quarter of 2016, compared with 161,000 Boe in the second quarter of 2015, representing a 13% year-over-year decline rate. Average oil production decreased by 13% or 14,000 barrels per day to 90,000 barrels per day in the three months ended June 30, 2016, compared to the same period of the prior year. NGL production decreased by 11% to 16,000 barrels per day. Natural gas production decreased by 14% to 202 MMcf per day, consistent with our focus on liquids. The second quarter production declines reflected our decision to withhold development capital and selectively defer workover and downhole maintenance activity in the first half of the year. We began increasing our activity levels gradually towards the end of the quarter. Additionally, temporary California pipeline disruptions negatively impacted our ability to sell all of the oil we produced in the second quarter of 2016, some of which we held in inventory at the end of the quarter. As a result, the actual second quarter production was slightly higher than the reported volumes, which represent sales. We expect this inventory to be sold in the third quarter of 2016 and reported as production at that time.

Derivative losses increased $101 million to $118 million for the three months ended June 30, 2016 due to volume and valuation changes in our outstanding derivative positions, partially offset by cash settlements.

Production costs for the three months ended June 30, 2016 decreased $54 million, to $188 million or $14.76 per Boe, compared to $242 million or $16.59 per Boe for the same period of 2015, resulting in a 22% decrease on an absolute dollar basis. The decrease was driven by cost reductions across our operations, particularly in well servicing efficiency, field personnel and lower natural gas prices, as well as management's decision to selectively defer workovers and downhole maintenance activity.

Our general and administrative expenses were lower for the three months ended June 30, 2016, compared to the same period of 2015, on a total dollar and per Boe basis, reflecting employee and contractor cost-reduction initiatives. The three months ended June 30, 2016 and 2015 included severance and other employee-related costs of $4 million and $10 million, respectively. The non-cash portion of general and administrative expenses, comprising equity compensation and pension costs, was approximately $7 million and $9 million for the three months ended June 30, 2016 and 2015, respectively.

DD&A expense decreased 45%, or $113 million, for the three months ended June 30, 2016, compared to the same period of 2015. Of this decrease, approximately $93 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2015, and approximately $20 million was attributable to lower volumes.

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

Exploration expense decreased 29%, or by $2 million, for the three months ended June 30, 2016, compared to the same period of 2015, primarily due to reduced exploration activity.

Interest and debt expense, net, decreased to $74 million for the three months ended June 30, 2016, compared to $83 million in the same period of 2015, due to amortization of the gain from the fourth quarter 2015 bond exchange, slightly offset by higher interest rates on our senior secured second lien notes and existing credit facility.

Other (income) expense for the three months ended June 30, 2016 largely consisted of the $44 million gain on retirement of notes and $31 million gain on non-core asset divestitures. Other expenses between the two periods were comparable.

For the three months ended June 30, 2016, we had no income tax benefit and a pre-tax loss of $140 million. During the second quarter of 2016, we recorded a full valuation allowance against the deferred tax assets that resulted from current period tax losses. For the same period of 2015, we had a benefit of $46 million and a pre-tax loss of $114 million. We had no effective tax for the three months ended June 30, 2016 due to the valuation allowance and a 40% effective tax rate for the three months ended June 30, 2015.

Six months ended June 30, 2016 vs. 2015

Oil and gas net sales decreased 37%, or $434 million, for the six months ended June 30, 2016, compared to the same period of 2015, due to an approximately $376 million negative impact from lower oil prices and volumes, $48 million from lower natural gas prices and volumes and $10 million from lower NGL prices. The lower realized oil prices resulted from a significant decrease in benchmark indexes. Our realized prices in 2016 included $75 million of cash generated from our hedging program. Daily oil and gas production volumes averaged 144,000 Boe in the six months ended June 30, 2016, compared with 163,000 Boe in the first half of 2015 representing a 12% year-over-year decline rate. Average oil production decreased by 11% or 12,000 barrels per day to 94,000 barrels per day in the first six months ended June 30, 2016, compared to the same period of the prior year. NGL production decreased by 6% to 17,000 barrels per day. Natural gas production decreased by 16% to 199 MMcf per day, consistent with our focus on liquids. Production declines in the first half of 2016 reflected our decision to withhold development capital and selectively defer workover and downhole maintenance activity. We began increasing our activity levels gradually towards the end of the second quarter.

Derivative losses increased $125 million to $143 million for the six months ended June 30, 2016 due to volume and valuation changes in our outstanding derivative positions, partially offset by cash settlements.

Production costs for the six months ended June 30, 2016 decreased by $112 million, to $372 million or $14.21 per Boe, compared to $484 million or $16.39 per Boe for the same period of 2015, resulting in a 23% decrease on an absolute dollar basis. The decrease was driven by cost reductions across our operations, particularly in well servicing efficiency, field personnel, energy use and lower natural gas prices, as well as management's decision to selectively defer workovers and downhole maintenance activity.

Our general and administrative expenses were lower for the six months ended June 30, 2016, compared to the same period of 2015, on a total dollar and per Boe basis, reflecting employee and contractor cost-reduction initiatives, as well as lower 2016 stock-based compensation costs due to our lower stock price. The six months ended June 30, 2016 and 2015 included severance and other employee-related costs of $18 million and $10 million, respectively. The non-cash portion of general and administrative expenses, comprising equity compensation and pension costs, was approximately $14 million and $18 million for the six months ended June 30, 2016 and 2015, respectively.

DD&A expense decreased 43%, or $219 million, for the six months ended June 30, 2016, compared to the same period of 2015. Of this decrease, approximately $183 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2015, and approximately $36 million was attributable to lower volumes.

Taxes other than on income decreased for the six months ended June 30, 2016, compared to the same period of 2015, largely reflecting lower property taxes assessed in the lower price environment.

Exploration expense decreased 58%, or by $14 million, for the six months ended June 30, 2016, compared to the same period of 2015, due to reduced exploration activity and lease rates.

Interest and debt expense, net, decreased to $148 million for the six months ended 2016, compared to $162 million in the same period of 2015, due to the amortization of the gain from the fourth quarter 2015 bond exchange slightly offset by higher interest rates on our senior secured second lien notes and existing credit facility.

Other (income) expense for the six months ended June 30, 2016 largely consisted of the $133 million gain from retirement of notes and the $31 million gain on non-core asset divestitures. Other expenses between the two periods were comparable.

For the six months ended June 30, 2016, we had an income tax benefit of $78 million and a pre-tax loss of $268 million. For the same period of 2015, we had a benefit of $115 million and a pre-tax loss of $283 million. Our effective tax rate was 29% and 41% for the six months ended June 30, 2016 and 2015, respectively. The lower rate for the six months ended June 30, 2016 reflected changes in the valuation allowance on our deferred tax assets.

Liquidity and Capital Resources

The primary source of liquidity and capital resources to fund our capital program and other obligations has been cash flow from operations. Operating cash flows are largely dependent on oil and natural gas prices, sales volumes and costs. Oil and natural gas prices declined significantly during fiscal year 2015 and declined further in early 2016, while rebounding modestly in the second quarter of 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

Much of the global exploration and production industry is challenged at current price levels, putting pressure on the industry's ability to generate positive cash flow and access capital. If commodity prices were to prevail through the year at about current levels, we would not anticipate a significant draw down on our revolving credit facility for our annual cash needs, including our current capital program. Our ability to borrow under our revolving credit facility is limited by the size of the facility, by our ability to comply with its covenants, including quarterly financial covenants, and by our borrowing base. Effective May 2, 2016, the borrowing base under our credit facilities was reaffirmed at $2.3 billion. As of June 30, 2016, we had approximately $460 million of available borrowing capacity under our revolving credit facility.

Unless prices for our products increase significantly, we expect we will need to amend the covenants under our credit facilities before the end of March 2017 in order to remain compliant. We can give no assurances that our lenders will amend our covenants. If we were to breach any of our credit facility covenants, our lenders would be permitted to accelerate the principal amount due under the credit facilities and foreclose on the assets securing them. If payment were accelerated under our credit facilities, it would result in a default under our outstanding notes and permit acceleration and foreclosure on the assets securing the secured notes.

In response to commodity price declines, we budgeted $50 million for our 2016 capital program compared to our 2015 capital investments of $401 million. In the first half of the year, we further reduced the pace of our capital program to below our initially budgeted level of $50 million. We have recently begun to increase our capital investments for the second half of the year to bring us back to our initially planned annual level. Our slowing of asset development from late 2015 through the first half of 2016, coupled with the selective deferral of expense workover activity, has led to a decline in production in the first half of 2016 that is in excess of our base decline range. We cannot guarantee our planned increase in investments will result in a rapid reversal of, or a significant increase in, production trends. Over the long term, if commodity prices fall again or remain at depressed levels we may experience continued declines in our production and reserves, which could reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations, the value of our assets and our borrowing base.

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

In our effort to delever our balance sheet, we took the opportunity to buy back over $100 million in principal amount of our notes in the open market for less than $13 million in the first quarter and to exchange approximately 2.1 million shares of common stock for approximately $80 million in principal amount of notes in the second quarter. We also had divestitures of several small non-core assets. Given the state of the commodity markets, we believe we need to further strengthen our balance sheet to competitively position the company for the longer term. As a result, we may from time to time seek to further reduce our outstanding debt using cash from asset sales or other monetizations, exchanging debt for other debt or equity securities or engaging in joint ventures. Such activities, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our credit facilities, perceived credit risk by counterparties and other factors. The amounts involved may be material. However, we can give no assurances that any of these efforts will be successful or adequately strengthen our balance sheet.

See Subsequent Events for discussion of our recently announced tender offer, proposed syndicated loan facility and proposed amendment to our Credit Facilities.

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



	2016				2017		2018
	Q3		Q4		Q1 - Q4		Q1 - Q4
Crude Oil
Calls:
Barrels per day	19,000		25,000		10,500		21,500
Weighted-average price per barrel	$	55.08	$	53.62	$	56.07	$	58.21

Puts:
Barrels per day	28,000		3,000		4,300		—
Weighted-average price per barrel	$	50.65	$	50.00	$	50.00	$	—

Swaps:
Barrels per day	1,000		29,000		—		—
Weighted-average price per barrel	$	61.25	$	49.43	$	—	$	—

Gas
Swaps:
MMBTU per day	330		5,500		—		—
Weighted-average price per MMBTU	$	3.13	$	3.50	$	—	$	—

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

Credit Facilities

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

Senior Notes

Other

Cash Flow Analysis



	Six months ended June 30,
	2016			2015
	(in millions)
Net cash flows provided by operating activities	$	44		$	232
Net cash flows used in investing activities	$	(18	)	$	(440	)
Net cash flows (used) provided by financing activities	$	(36	)	$	231
Adjusted EBITDAX ^(a)	$	284		$	468

_______________________________

(a)

We define adjusted EBITDAX consistent with our Credit Facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other non-cash, unusual and infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and 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 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,
	2016		2015
	(in millions)
Net cash provided by operating activities	$	44	$	232
Cash interest	180		149
Exploration expenditures	10		17
Other changes in operating assets and liabilities	41		67
Plant turnaround and other costs	9		3
Adjusted EBITDAX	$	284	$	468

Our net cash provided by operating activities was $44 million and $232 million for the six months ended June 30, 2016 and 2015, respectively. The first half of 2016, as compared with the same period in 2015, reflected lower revenues of $374 million, primarily due to lower commodity prices and volumes, net of cash generated from our hedging program, partially offset by lower production costs of $110 million, general and administrative expenses of $30 million and taxes other than on income of $30 million as well as the positive effect of working capital changes primarily related to trade receivables and accrued liabilities.

Our net cash flow used by investing activities decreased $422 million for the six months ended June 30, 2016, compared to the same period of 2015, primarily due to lower capital investments.

Our net cash flow used by financing activities of $36 million for the six months ended June 30, 2016 included approximately $42 million in net proceeds on the Revolving Credit Facility, $61 million in payments on the Term Loan and $20 million in debt repurchases and other costs. Our net cash flow provided by financing activities of $231 million for the six months ended June 30, 2015 included approximately $230 million in net borrowings on the Revolving Credit Facility.

2016 Capital Program

For 2016, we currently have a $50 million capital program designed primarily to maintain the mechanical integrity of our facilities and systems and operate them safely. Our capital for the six months ended June 30, 2016 was $26 million, of which $5 million related to the second quarter. Of the total amount, $19 million was for the planned turnaround at our Elk Hills power plant, of which payment of $14 million was deferred to future periods. The remaining amount is for other mechanical integrity projects and workovers. We significantly slowed second quarter capital investment in response to low commodity prices. Our decision to withhold development capital in the first half of the year reduced our production levels, particularly in the second quarter. We are increasing the level of our capital activity in the second half of the year to a pace that will bring the full-year investment to a level consistent with the $50 million capital program. We expect that this higher activity level will reduce our production decline rate in the second half of the year to bring the full year decline to a range consistent with our stated decline range. However, sustained low-price periods may materially affect the quantities of oil and gas reserves we can economically produce over the longer term.

We focus on creating value and are committed to internally fund our capital budget with operating cash flows. Our low decline assets plus our high level of operational control and absence of long term commitments give us the flexibility to adjust the level of such capital investments as circumstances warrant. In light of current commodity prices, we have built a dynamic budget for 2016 that can be adjusted to align investments with projected cash flows. We will monitor prices and cash flow throughout the year and, if oil prices improve, may deploy additional capital focusing on a combination of capital workovers and new wells that meet our Value Creation Index (VCI) investment metrics, while abiding by our financial covenants.

Subsequent Events

We are concurrently seeking to amend our Credit Facilities to permit the consummation of these offers and the incurrence of a new syndicated loan facility. We also expect that the amendment will, among other things, reduce the Revolving Credit Facility commitments from $1.6 billion to $1.4 billion, provide covenant relief until the end of the first quarter of 2018 and grant a lien on substantially all of our assets not currently pledged to secure the Credit Facilities.

Lawsuits, Claims, Contingencies and Commitments

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

Significant Accounting and Disclosure Changes

Safe Harbor Statement Regarding Outlook and Forward-Looking Information

The information in this document includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business prospects, budgets, drilling and workover program, maintenance capital, projected production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect our results of operations and financial position appear in Part I, Item 1A, Risk Factors of the 2015 Form 10-K.

Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency of our operating cash flow to fund planned capital expenditures; faster than expected production decline rates; inability to implement our capital investment program; inability to replace reserves; inability to obtain government permits and approvals; inability to monetize selected assets; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; risks related to our disposition and acquisition activities; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; the recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; the effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the Spin-off and the agreements related thereto. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

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


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For the three and six months ended June 30, 2016, there were no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A) - Quantitative and Qualitative Disclosures About Market Risk in the 2015 Form 10-K, except for the following matters.

Commodity Price Risk

We currently have the following Brent-based crude oil and NYMEX-based gas hedges:



	2016				2017		2018
	Q3		Q4		Q1 - Q4		Q1 - Q4
Crude Oil
Calls:
Barrels per day	19,000		25,000		10,500		21,500
Weighted-average price per barrel	$	55.08	$	53.62	$	56.07	$	58.21

Puts:
Barrels per day	28,000		3,000		4,300		—
Weighted-average price per barrel	$	50.65	$	50.00	$	50.00	$	—

Swaps:
Barrels per day	1,000		29,000		—		—
Weighted-average price per barrel	$	61.25	$	49.43	$	—	$	—

Gas
Swaps:
MMBTU per day	330		5,500		—		—
Weighted-average price per MMBTU	$	3.13	$	3.50	$	—	$	—

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

As of June 30, 2016, we had derivative assets of $18 million and derivative liabilities of $99 million carried at fair value, as determined from prices provided by external sources that are not actively quoted, which mature in 2016 through 2018.

Credit Risk

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

As of June 30, 2016, the substantial majority of the credit exposures related to our business was with investment grade counterparties. We believe exposure to credit-related losses related to our business at June 30, 2016 was not material and losses associated with credit risk have been insignificant for all years presented.


Item 4.	Controls and Procedures

Our President and Chief Executive Officer and our Senior Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Senior Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2016.

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the second quarter of 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION


Item 1.	Legal Proceedings

For information regarding legal proceedings, see Note 6 to the consolidated condensed financial statements in Part I of this Form 10-Q and Part I, Item 3, "Legal Proceedings" in the Form 10-K for the year ended December 31, 2015.


Item 1.A.	Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading "Risk Factors" in our Form 10-K for the year ended December 31, 2015.


Item 5.	Other Disclosures

None


Item 6.	Exhibits



	3.1	Amended and Restated Certificate of Incorporation of California Resources Corporation (incorporated by reference herein to Exhibit 3.1 to the Registrant’s Registration Statement on Form 8-K filed on June 3, 2016).

	4.1*	Guarantor Supplemental Indenture dated as of March 4, 2016, among California Resources Corporation, California Resources Coles Levee, LLC, certain other guarantors and The Bank of New York Mellon Trust Company, N.A.,, as trustee.

	4.2*	Guarantor Supplemental Indenture dated as of March 4, 2016, among California Resources Corporation, California Resources Coles Levee, L.P., certain other guarantors and The Bank of New York Mellon Trust Company, N.A.,, as trustee.

	10.1	California Resources Corporation Long-Term Incentive Plan, as amended and restated effective May 4, 2016 (incorporated by reference herein to Annex B to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 23, 2016).

	10.2	First Amendment to the California Resources Corporation 2014 Employee Stock Purchase Plan effective May 4, 2016 (incorporated by reference herein to Annex C-1 to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 23, 2016).

	10.3	Fourth Amendment to Credit Agreement, dated April 22, 2016, among California Resources Corporation and JP Morgan Chase Bank, N.A., as Administrative Agent, A Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of credit Issuer (incorporated by reference herein Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed April 22, 2016).

	10.4*	Guarantor Supplemental Indenture No. 2, dated as of April 29, 2016, among California Resources Corporation, California Resources Coles Levee, L.P. and California Resources Coles Levee, LLC, certain other guarantors and Wilmington Trust, National Association, as trustee.

	10.5*	California Resources Corporation Long-Term Incentive Plan, 2016 Annual Incentive Award Summary.

	10.6*	Form of California Resources Corporation Long-Term Incentive Plan Restricted Stock Unit Award Terms and Conditions.

	12	Computation of Ratios of Earnings to Fixed Charges.

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

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

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

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

	101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* - Filed herewith.

SIGNATURES

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



	CALIFORNIA RESOURCES CORPORATION



DATE:	August 4, 2016	/s/ Roy Pineci
		Roy Pineci
		Executive Vice President - Finance
		(Principal Accounting Officer)

EXHIBIT INDEX

EXHIBITS



	3.1	Amended and Restated Certificate of Incorporation of California Resources Corporation (incorporated by reference herein to Exhibit 3.1 to the Registrant’s Registration Statement on Form 8-K filed on June 3, 2016).

	4.1*	Guarantor Supplemental Indenture dated as of March 4, 2016, among California Resources Corporation, California Resources Coles Levee, LLC, certain other guarantors and The Bank of New York Mellon Trust Company, N.A.,, as trustee.

	4.2*	Guarantor Supplemental Indenture dated as of March 4, 2016, among California Resources Corporation, California Resources Coles Levee, L.P., certain other guarantors and The Bank of New York Mellon Trust Company, N.A.,, as trustee.

	10.1	California Resources Corporation Long-Term Incentive Plan, as amended and restated effective May 4, 2016 (incorporated by reference herein to Annex B to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 23, 2016).

	10.2	First Amendment to the California Resources Corporation 2014 Employee Stock Purchase Plan effective May 4, 2016 (incorporated by reference herein to Annex C-1 to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 23, 2016).

	10.3	Fourth Amendment to Credit Agreement, dated April 22, 2016, among California Resources Corporation and JP Morgan Chase Bank, N.A., as Administrative Agent, A Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of credit Issuer (incorporated by reference herein Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed April 22, 2016).

	10.4*	Guarantor Supplemental Indenture No. 2, dated as of April 29, 2016, among California Resources Corporation, California Resources Coles Levee, L.P. and California Resources Coles Levee, LLC, certain other guarantors and Wilmington Trust, National Association, as trustee.

	10.5*	California Resources Corporation Long-Term Incentive Plan, 2016 Annual Incentive Award Summary.

	10.6*	Form of California Resources Corporation Long-Term Incentive Plan Restricted Stock Unit Award Terms and Conditions.

	12	Computation of Ratios of Earnings to Fixed Charges.

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

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

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

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

	101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* - Filed herewith.