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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
    
FORM 8-K
    
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): February 16, 2017
    
California Resources Corporation
(Exact Name of Registrant as Specified in Charter)
 
   
 
 
 
 
Delaware
001-36478
46-5670947
(State or Other Jurisdiction of
Incorporation)
(Commission
File Number)
(IRS Employer
Identification No.)
 
 
 
9200 Oakdale Avenue, Suite 900
Los Angeles, California
91311
(Address of Principal Executive Offices)
(Zip Code)

Registrant’s Telephone Number, Including Area Code: (888) 848-4754
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)
    
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨      Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
¨      Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
¨      Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
¨      Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))







Item 1.01     Entry into a Material Definitive Agreement.
On February 14, 2017, California Resources Corporation (the “Company”), amended the Credit Agreement, among the Company, as the Borrower, JP Morgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer, and the Lenders, dated as of September 24, 2014, as previously amended February 25, 2015, November 6, 2015, February 23, 2016, April 22, 2016 and August 17, 2016. The amendment makes changes to facilitate additional joint venture transactions, eliminate a capital expenditure restriction, adopt a minimum liquidity requirement and facilitate certain other actions.
A copy of the amendment is filed as Exhibit 10.1 to this report.
Item 2.02     Results of Operations and Financial Condition.
On February 16, 2017, the Company issued a press release announcing its financial condition and results of operations for the three and twelve months ended December 31, 2016. A copy of the press release is furnished as Exhibit 99.1 to this report on Form 8-K and is incorporated herein by reference.
The information contained in this report and the exhibit hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.
Statements contained in the exhibit to this report that state the Company’s or its management’s expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions of the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. It is important to note that the Company’s actual results could differ materially from those projected in such forward-looking statements. Factors that could affect those results include those mentioned in the documents that the Company has filed with the Securities and Exchange Commission (the “SEC”).
The Company undertakes no duty or obligation to publicly update or revise the information contained in this report, although the Company may do so from time to time as management believes is warranted. Any such updating may be made through the filing of other reports or documents with the SEC, through press releases or through other public disclosure including disclosure in the Investor Relations portion of the Company’s website.
Item 5.02
Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.
On February 13, 2017, Mr. Tim Sloan provided notice to the Company of his intent to resign from the Company’s Board of Directors effective as of February 28, 2017, as a result of his recent appointment as President and CEO and election to the board of Wells Fargo & Company. Mr. Sloan’s decision to resign from the Company’s Board was not related to any disagreement with the Company regarding its operations, policies or practices. 
On February 14, 2017, the Board elected Mr. Harry McMahon to fill the vacancy resulting from the departure of Mr. Sloan, effective as of March 1, 2017. Mr. McMahon will serve the remaining term of Mr. Sloan (expiring in 2018) as an independent director, and will serve on the Audit Committee and the Compensation Committee of the Board. Most recently, Mr. McMahon served as Executive Vice Chairman of Bank of America Merrill Lynch. Mr. McMahon's experience over three decades in investment banking is expected to provide the Board with deep insight into corporate and financial strategy and capital markets.

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There are no arrangements or understandings between Mr. McMahon and any other persons under which he was selected as a director. Mr. McMahon will receive the same director compensation as is paid to the other non-employee directors under the Company’s compensation program for non-employee directors which are described and may be reviewed in Company’s most recent proxy statement.
Item 8.01     Other Events.
On February 16, 2017, the Company issued a press release announcing a joint venture with Benefit Street Partners to invest up to $250 million in certain of the Company’s oil and gas properties in California.  A copy of the press release is furnished as Exhibit 99.2 to this report on Form 8-K, and is incorporated herein by reference.
Statements contained in the exhibit to this report that state the Company’s or its management’s expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions of the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. It is important to note the Company’s actual results could differ materially from those projected in such forward-looking statements. Factors that could affect those results include those identified in the documents that the Company has filed with the SEC.
The Company undertakes no duty or obligation to publicly update or revise the information contained in this report although the Company may do so from time to time as management believes is warranted. Any such updating may be made through the filing of other reports or documents with the SEC.
Item 9.01    Financial Statements and Exhibits.
(d)     Exhibits
Exhibit No.

 
Description

99.1
 
Earnings Press Release dated February 16, 2017
99.2
 
Press Release dated February 16, 2017
10.1
 
Sixth Amendment to Credit Agreement dated as of February 14, 2017 among California Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer, and the Lenders


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SIGNATURE
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 hereunto duly authorized.
 
California Resources Corporation
 
 
 
 
 
 
 
/s/ Roy Pineci
 
Name:
Roy Pineci
 
Title:
Executive Vice President - Finance



DATED: February 16, 2017



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EXHIBIT INDEX

Exhibit No.

 
Description

99.1
 
Earnings Press Release dated February 16, 2017
99.2
 
Press Release dated February 16, 2017
10.1
 
Sixth Amendment to Credit Agreement dated as of February 14, 2017 among California Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer, and the Lenders


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Execution Version
Exhibit 10.1



SIXTH AMENDMENT

TO

CREDIT AGREEMENT

DATED AS OF FEBRUARY 14, 2017

AMONG

CALIFORNIA RESOURCES CORPORATION,
AS THE BORROWER,

JPMORGAN CHASE BANK, N.A.,
AS ADMINISTRATIVE AGENT, SWINGLINE LENDER
AND A LETTER OF CREDIT ISSUER,

BANK OF AMERICA, N.A.,
AS SYNDICATION AGENT, SWINGLINE LENDER
AND A LETTER OF CREDIT ISSUER,

AND

THE LENDERS
PARTY HERETO




US 4852243v.8
        

SIXTH AMENDMENT TO CREDIT AGREEMENT
This Sixth Amendment to the Credit Agreement (this “ Amendment ”) dated as of February 14, 2017, is among California Resources Corporation, a Delaware corporation (the “ Borrower ”), each of the undersigned Guarantors, each Lender (as defined below) party hereto, and JPMorgan Chase Bank, N.A., as administrative agent for the Lenders (in such capacity, together with its successors and assigns, the “ Administrative Agent ”).
RECITALS
A. The Borrower, the Administrative Agent and the banks and other financial institutions from time to time party thereto (together with their respective successors and assigns in such capacity, each a “ Lender ”) have entered into that certain Credit Agreement dated as of September 24, 2014 (as amended by the First Amendment to Credit Agreement dated as of February 25, 2015, the Second Amendment to Credit Agreement dated as of November 2, 2015, the Third Amendment dated as of February 23, 2016, the Fourth Amendment dated as of April 22, 2016, the Fifth Amendment dated as of August 12, 2016 and as further amended, restated, modified or supplemented from time to time, the “ Credit Agreement ”).
B. The Borrower desires to invest in one or more Development Joint Ventures to explore for and develop Oil and Gas Properties and to convey to such Development Joint Ventures one or more net profits interests.
C. The Borrower has requested and the Lenders party hereto have agreed to amend certain provisions of the Credit Agreement on the terms and conditions set forth herein.
D. NOW, THEREFORE, to induce the Administrative Agent and the Lenders to enter into this Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
Section 1. Definitions . Unless otherwise defined in this Amendment, each capitalized term used in this Amendment has the meaning assigned to such term in the Credit Agreement. Unless otherwise indicated, all section references in this Amendment refer to sections of the Credit Agreement.
Section 2.      Amendments to Credit Agreement .
2.1      Amendments to Section 1.1 .
(a)      The following defined terms are hereby amended and restated in their entirety or added in their entirety, in each case to read as follows:
“ Sanctioned Country ” shall mean, at any time, a country or territory which is itself the subject or target of any Sanctions (at the time of this Agreement, including, but not limited to, the Crimea region of Ukraine, Cuba, Iran, North Korea, Sudan and Syria).

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“ NPI JV ” shall mean any Development Joint Venture into which any Credit Party contributes or sells a net profits interest which is or is intended to be a real property interest.
“ Sixth Amendment ” shall mean that certain Sixth Amendment to Credit Agreement, dated as of February 14, 2017, among the Borrower, the Administrative Agent and the Lenders party thereto.
“ Sixth Amendment Effective Date ” shall mean the Effective Date (as defined in the Sixth Amendment).
“ Subsidiary ” of any Person shall mean and include (a) any corporation more than 50% of whose Stock of any class or classes having by the terms thereof ordinary voting power to elect a majority of the directors of such corporation (irrespective of whether or not at the time Stock of any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such Person directly or indirectly through Subsidiaries and (b) any limited liability company, partnership, association, joint venture or other entity of which such Person directly or indirectly through Subsidiaries has more than a 50% Stock at the time; provided , that any Development Joint Venture that is a Person shall not be deemed to be a Subsidiary of the Borrower or of any of its Subsidiaries. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower. A Royalty Trust shall not constitute a “Subsidiary” of the Borrower or its Subsidiaries.
2.2      Amendment to Section 5.2 .
(a)      Subsection 5.2(e) of the Credit Agreement is amended and restated in its entirety to read as follows:
(e)     Repayment of Loans Following Disposition of Non-Borrowing Base Properties . If the Borrower or any one of the other Credit Parties consummates a Disposition (other than (i) Dispositions valued in good faith by the Borrower at less than $1,000,000 individually or $10,000,000 in the aggregate for any fiscal year of the Borrower, (ii) Exploration and Development Dispositions for which any cash received is used to pay or reimburse costs and expenses incurred in the conduct of exploration and development operations in connection with the related Development Joint Venture, farm-ins or farm-outs and (iii) Dispositions of any non-Borrowing Base Properties (including net profits interests) to any Development Joint Venture (including any NPI JV) on or after the Sixth Amendment Effective Date for which the consideration received is reinvested in any Development Joint Venture (including any NPI JV) or in any of the Credit Parties’ Oil and Gas Properties), to a Person other than the Borrower or any one of the other Credit Parties (x) of properties not constituting Borrowing Base Properties or (y) of any Stock or Stock Equivalents of any Subsidiary owning properties not constituting Borrowing Base Properties (each a “ Non-Borrowing Base Disposition ”), the Borrower shall, on the Business Day after receiving such

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proceeds, (I) prepay the Term Loans at par in an aggregate principal amount equal to the lesser of (A) 100% of the Net Cash Proceeds obtained from such Non-Borrowing Base Disposition less the sum (up to an amount equal to 50% of the Net Cash Proceeds obtained from such Non-Borrowing Base Disposition) of the following (1) any Net Cash Proceeds used or reserved for a purpose permitted by Section 11.7(a)(i) , (2) any Net Cash Proceeds used or otherwise reserved for general corporate purposes (other than, for the avoidance of doubt, prepayment of any Indebtedness (excluding prepayment of First Out Obligations)) and (3) any Net Cash Proceeds used to make O&G Expenditures, and (B) the sum of the then-outstanding Term Loans, and (II) repay the Revolving Loans with any such Net Cash Proceeds remaining after giving effect to the prepayment of Term Loans required by Section 5.2(e)(I) ; provided , that contemporaneously with any repayment of Revolving Loans made pursuant to Section 5.2(e)(II) , the Total Revolving Commitment shall be reduced by the amount of such repayment.
(b)      Subsection 5.2(f) of the Credit Agreement is amended and restated in its entirety to read as follows:
(f)      Repayment of Loans Following Disposition of Borrowing Base Properties . If the Borrower or any one of the other Credit Parties consummates a Disposition (other than (i) Dispositions valued in good faith by the Borrower at less than $1,000,000 individually or $10,000,000 in the aggregate for any fiscal year of the Borrower, (ii) Exploration and Development Dispositions for which any cash received is used to pay or reimburse costs and expenses incurred in the conduct of exploration and development operations in connection with the related Development Joint Venture, farm-ins or farm-outs and (iii) Dispositions of Proved Reserves (including net profits interests) to any Development Joint Venture (including any NPI JV) on or after the Sixth Amendment Effective Date for which the consideration received is reinvested in any Development Joint Venture (including any NPI JV) or in any of the Credit Parties’ Oil and Gas Properties), to a Person other than the Borrower or any one of the other Credit Parties of Borrowing Base Properties or of any Stock or Stock Equivalents of any Subsidiary owning Borrowing Base Properties, the Borrower shall, on the Business Day after receiving such proceeds, (I) prepay the Term Loans at par in an aggregate principal amount equal to the lesser of (A) 100% of the Net Cash Proceeds obtained from such Disposition and (B) the sum of the then-outstanding Term Loans and (II) repay the Revolving Loans with any such Net Cash Proceeds remaining after giving effect to the prepayment of Term Loans required by Section 5.2(f)(I); provided , that contemporaneously with any repayment of Revolving Loans made pursuant to Section 5.2(f)(II) , the Total Revolving Commitment shall be reduced by the amount of such repayment.
(c)      Subsection 5.2(i) of the Credit Agreement is amended by revising clause (A) of the proviso in its entirety to read as follows:
(A) each prepayment of any Revolving Loans made pursuant to a Borrowing shall be applied pro rata among such Revolving Loans and each prepayment of any Term Loans made pursuant to a Borrowing shall be applied in forward order of maturity among such

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Term Loans; provided that any prepayment of Term Loans made pursuant to Section 5.2(e) shall be applied in inverse order of maturity among such Term Loans
2.3      Amendment to Section 10.10 .     Subsection 10.10(f) of the Credit Agreement is amended and restated in its entirety to read as follows:
(f)    Subject to any applicable limitations set forth in the Security Documents or the Pledge Agreement, upon the occurrence and during the continuation of a Borrowing Base Trigger Period, as soon as practicable using commercially reasonable efforts, but in any event within thirty (30) days (or such longer period as the Administrative Agent shall agree in its reasonable discretion) of the Sixth Amendment Effective Date, the Borrower will execute and cause its Material Subsidiaries to execute any Mortgages necessary to provide an Acceptable Security Interest subject to one-action rule waivers (to the extent permitted by applicable law) on all non-Borrowing Base Properties of the Credit Parties having a value in excess of $10,000,000, individually or in the aggregate; provided that in the event such non-Borrowing Base Properties are acquired during a Borrowing Base Trigger Period, the Borrower shall execute such Mortgages as soon as practicable using commercially reasonable efforts, but in any event within ten Business Days (10) days (or such longer period as the Administrative Agent shall agree) after such non-Borrowing Base Properties having a value in excess of $10,000,000, individually or in the aggregate, are acquired; provided further that (i) such assets may be subject to Liens permitted under Section 11.2 and (ii) no intention to subordinate the Acceptable Security Interest of the Administrative Agent and the Secured Parties pursuant to the Security Documents is to be hereby implied or expressed by the permitted existence of such Permitted Liens.
2.4      Amendment to Section 11.4 . Section 11.4 of the Credit Agreement is amended as follows:
(a)      deleting the word “and” at the end of subsection 11.4(a)(xiii);
(b)      adding the word “and” at the end of subsection 11.4(a)(xiv);
(c) adding a new clause (xv) immediately after subsection 11.4(a)(xiv) to read as follows:
(xv)    Disposition of any easement on any surface rights to any Governmental Authority to satisfy the requirements of any “conservation easements” or similar programs established by any Governmental Authority; provided that such Disposition does not materially impair the exploitation and development of the affected Oil and Gas Properties;
(d) amending the proviso at the end of subsection 11.4(a) in its entirety to read as follows:
provided , however , that at least 75% (or with respect to Section 11.4(a)(xiii) only, (x) 50%, in the event the Borrower’s Total Debt Leverage Ratio is greater than 4:00 to 1:00 or (y) 40%, in the event the Borrower’s Total Debt Leverage Ratio is less than or equal to 4:00 to 1:00) of the consideration received by the Borrower or any Subsidiary in connection with a Disposition permitted under Section 11.4(a) is in the form of cash, other than (A) any Disposition permitted under

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subsections (i), (iii)-(iv), (vii)-(ix), (xi), (xii) or (xv) of Section 11.4(a) , (B) for the avoidance of doubt, any Dispositions of net profits interests to any NPI JV on or after the Sixth Amendment Effective Date and (C) any Disposition consisting of (x) farm-in or farm-out transactions permitted under this Section 11.4(a) or (y) Proved Reserves disposed of to a Development Joint Venture (including an NPI JV); provided that (1) any portion of such Dispositions under clauses (B) or (C) constituting Borrowing Base Properties is subject to the terms of Section 11.4(a)(ii) and (2) the PV-9, as set forth in the most recently delivered Reserve Report, of such Borrowing Base Properties Disposed to any NPI JV or Development Joint Venture, is less than or equal to $250,000,000 in the aggregate during the term of this Agreement (any transaction permitted under clauses (B) or (C) an “ Exploration and Development Disposition ”)); and provided further that if the consideration for any such Disposition pursuant to clause (A) above equals or exceeds $100,000,000, such Disposition shall be for Fair Market Value and the determination of Fair Market Value shall be confirmed by an investment bank or made by an independent third-party reasonably acceptable to the Administrative Agent and provided further that any cash received in connection with an Exploration and Development Disposition transaction in order to fund costs and expenses incurred in the conduct of exploration and development operations may be used by the Borrower or any Subsidiary for funding such development.
2.5      Amendment to Section 11.7 . Subsection 11.7(a) of the Credit Agreement is amended and restated in its entirety to read as follows:
(a)    Except as permitted by Section 11.7(b) , the Borrower shall not, and shall not permit the other Credit Parties to, make any prepayment, repurchase, redemption or defeasance of the Senior Notes, any Permitted Junior Indebtedness or any Permitted Additional Debt (it being understood that payments of regularly scheduled cash interest in respect of, payment of principal on the scheduled maturity date of, the Senior Notes or Permitted Junior Indebtedness (only to the extent permitted under the definition thereof) or Permitted Additional Debt shall be permitted prior to maturity, as applicable), except the Borrower or any Credit Party, as applicable, may:
(i)    prepay, repurchase, redeem or defease any Permitted Additional Debt, the Senior Notes or Permitted Second Lien Indebtedness with an amount up to (x) in the event the Borrower’s Total Debt Leverage Ratio is greater than 4:00 to 1:00, 50% multiplied by the sum of (x) Net Cash Proceeds plus (y) Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness obtained as consideration for a Non-Borrowing Base Disposition (such amount reduced by any portion of the total consideration for such Disposition received by the Borrower or such other Credit Party in the form of Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness (which Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness may comprise up to 50% of the total consideration for such Disposition)) or (y) in the event the Borrower’s Total Debt Leverage Ratio is less than or equal to 4:00

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to 1:00, 60% multiplied by the sum of (x) Net Cash Proceeds plus (y) Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness obtained as consideration for a Non-Borrowing Base Disposition; provided that any such Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness obtained as consideration shall be valued at Fair Market Value and shall comprise no more than 50% of the total consideration for such Disposition; and
(ii)    prepay, repurchase, redeem or defease any Permitted Additional Debt, the Senior Notes or Permitted Second Lien Indebtedness with an amount up to 75% multiplied by the sum of (x) Net Cash Proceeds plus (y) Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness obtained as proceeds, in each case of any incurrence of Indebtedness permitted under Section 11.1(aa) (such amount reduced by any portion of the total proceeds of such incurrence received by the Borrower or such other Credit Party in the form of Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness (which Permitted Additional Debt, Senior Notes or Permitted Second Lien Indebtedness may comprise up to 75% of such total proceeds));
provided that (1) the principal amount of such Senior Notes, Permitted Second Lien Indebtedness, or Permitted Additional Debt, as applicable (excluding the 5% Senior Notes due 2020 and the 5½% Senior Notes due 2021, if any, that are repurchased at a discount pursuant to clause (2) below), is prepaid, repurchased, redeemed or defeased at a discount of 35% to par or greater (calculated for each prepayment, repurchase, redemption or defeasance on a weighted average basis giving effect (in addition to the discount in such prepayment, repurchase, redemption or defeasance) to any prior discount in prepayments, repurchases, redemptions or defeasances that have occurred from the first day of the calendar quarter in which such prepayment, repurchase, redemption or defeasance is consummated to the date such prepayment, repurchase, redemption or defeasance is consummated (it being understood that such calculation shall be made exclusive of any consideration paid to the holders of such Indebtedness in the form of Stock or the cash proceeds of Stock used to prepay, repurchase, redeem or defease such Indebtedness)), (2) the aggregate consideration paid to repay, repurchase, redeem or defease at a discount to par (which discount may be less than 35% to par) after the Sixth Amendment Effective Date (A) any 5% Senior Notes due 2020 will not exceed $100,000,000 in the aggregate and (B) any 5½% Senior Notes due 2021 will not exceed $40,000,000 in the aggregate, and (3) (A) after giving pro

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forma effect to such prepayment repurchase, redemption or defeasance, Liquidity is equal to $250,000,000 or greater, (B) no Event of Default has occurred and is continuing, and (C) after giving pro forma effect to such prepayment, repurchase, redemption or defeasance and any related pro forma adjustment (including, without limitation, any substantially concurrent incurrence of Indebtedness or Disposition and with such pro forma adjustments including the recalculation of PV-10 on a pro forma basis), the Borrower is in pro forma compliance with the Financial Performance Covenants set forth in Section 11.11. For the avoidance of doubt, for the purposes of this Section 11.7(a) , the amount of any Senior Notes or Permitted Second Lien Indebtedness shall be calculated using the Fair Market Value of such Senior Notes or Permitted Second Lien Indebtedness at the time of the prepayment, repurchase, redemption or defeasance thereof.
2.6      Amendment to Section 11.11 . Section 11.11 of the Credit Agreement is hereby amended to by adding a new clause (g) after clause (f) as follows:
(g)     Liquidity . During a Borrowing Base Trigger Period, the Borrower will not permit Liquidity to be less than $250,000,000 as of the last day of each calendar month. Together with the delivery of the information required to be delivered pursuant to Section 10.15 , the Borrower will deliver a certificate of an Authorized Officer certifying the amount of Liquidity as of the last day of the preceding calendar month and showing, in reasonable detail, supporting information and calculations reflecting the amount of such Liquidity.
2.7      Amendment to Section 11.15 . Section 11.15 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:
11.15      [Reserved] .
Section 3.      Effectiveness. This Amendment shall become effective on the first date on which each of the conditions set forth in this Section 3 is satisfied (the “ Effective Date ”):
3.1      The Administrative Agent shall have received duly executed counterparts (in such number as may be requested by the Administrative Agent) of this Amendment from the Borrower, each Guarantor and the Majority Lenders.
3.2      The Borrower shall have paid (a) an amendment fee payable to the Administrative Agent for the account of each of the Revolving Lenders and Term Loan Lenders (including JPMorgan Chase Bank, N.A.) who has consented to this Amendment by submitting its signature page on or before 4:00 P.M. Houston time on Monday, February 13, 2017 in an amount equal to 10 basis points on each such Revolving Lender’s Revolving Commitment and such Term Loan Lender’s Term Loan Commitment, as applicable, in effect on the Effective Date and (b) to the extent invoiced, all fees

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and other amounts due and payable on or prior to the Effective Date, including all reasonable out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.
3.3      No Default or Event of Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Amendment.
Section 4.      Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
Section 5.      Miscellaneous .
5.1      (a) On and after the effectiveness of this Amendment, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in each other Credit Document to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as amended or otherwise modified by this Amendment; (b) the execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any default of the Borrower or any right, power or remedy of the Administrative Agent or the Lenders under any of the Credit Documents, nor constitute a waiver of any provision of any of the Credit Documents; (c) this Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument and any of the parties hereto may execute this Agreement by signing any such counterpart; and (d) delivery of an executed counterpart of a signature page to this Amendment by telecopier or electronic mail shall be effective as delivery of a manually executed counterpart of this Amendment.
5.2      Neither the execution by the Administrative Agent or the Lenders of this Amendment, nor any other act or omission by the Administrative Agent or the Lenders or their officers in connection herewith, shall be deemed a waiver by the Administrative Agent or the Lenders of any defaults which may exist or which may occur in the future under the Credit Agreement and/or the other Credit Documents (collectively “ Violations ”). Similarly, nothing contained in this Amendment shall directly or indirectly in any way whatsoever either: (a) impair, prejudice or otherwise adversely affect the Administrative Agent’s or the Lenders’ right at any time to exercise any right, privilege or remedy in connection with the Credit Documents with respect to any Violations; (b) except for the amendments set forth herein, amend or alter any provision of the Credit Agreement, the other Credit Documents, or any other contract or instrument; or (c) constitute any course of dealing or other basis for altering any obligation of the Borrower or any right, privilege or remedy of the Administrative Agent or the Lenders under the Credit Agreement, the other Credit Documents, or any other contract or instrument. Nothing in this letter shall be construed to be a consent by the Administrative Agent or the Lenders to any Violations.
5.3      The Borrower and each Guarantor hereby (a) acknowledges the terms of this Amendment; (b) ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Credit Document to which it is a party and agrees that each Credit Document to which it is a party remains in full force and effect, except as expressly amended or modified hereby; and (c) represents and warrants to the Lenders that as of the Effective Date, after giving effect to the terms of this Amendment: (i) all of the representations and warranties contained

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in each Credit Document to which it is a party are true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct) as of such specified earlier date, and (ii) no Default or Event of Default has occurred and is continuing.
5.4      This Amendment is a Credit Document as defined and described in the Credit Agreement and all of the terms and provisions of the Credit Agreement relating to Credit Documents shall apply hereto.
5.5      THE CREDIT AGREEMENT AND THE OTHER CREDIT DOCUMENTS, INCLUDING THIS AMENDMENT, EMBODY THE ENTIRE AGREEMENT AND UNDERSTANDING BETWEEN THE PARTIES AND SUPERSEDE ALL OTHER AGREEMENTS AND UNDERSTANDINGS BETWEEN SUCH PARTIES RELATING TO THE SUBJECT MATTER HEREOF AND THEREOF AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
[Signature Pages Follow]


9
US 4852243v.8

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their officers thereunto duly authorized as of the date first above written.
BORROWER:
 
CALIFORNIA RESOURCES CORPORATION
 
 
 
 
 
 
 
 
By: /s/ Marshall D. Smith
 
 
Name: Marshall D. Smith
 
 
Title: Senior Executive Vice President and Chief Financial Officer
 
 
 


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






GUARANTORS:
CALIFORNIA HEAVY OIL, INC.
CALIFORNIA RESOURCES LONG BEACH, INC.
CALIFORNIA RESOURCES PETROLEUM CORPORATION
CALIFORNIA RESOURCES PRODUCTION CORPORATION
CALIFORNIA RESOURCES TIDELANDS, INC.
SOUTHERN SAN JOAQUIN PRODUCTION, INC.
THUMS LONG BEACH COMPANY
 
 
 
By:
/s/ Marshall D. Smith
 
Name: Marshall D. Smith
 
Title: Senior Executive Vice President and
Chief Financial Officer


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
CALIFORNIA RESOURCES ELK HILLS, LLC
CRC CONSTRUCTION SERVICES, LLC
CRC SERVICES, LLC
SOCAL HOLDING, LLC
 
 
 
By:
/s/ Marshall D. Smith
 
Name: Marshall D. Smith
 
Title: Senior Executive Vice President and
Chief Financial Officer of California Resources Corporation, its Sole Member


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
CALIFORNIA RESOURCES WILMINGTON, LLC
 
 
 
By:
/s/ Marshall D. Smith
 
Name: Marshall D. Smith
 
Title: Senior Executive Vice President and
Chief Financial Officer of California Resources Corporation, its Sole Member



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
CRC MARKETING, INC.
 
 
 
By:
/s/ D. Adam Smith
 
Name: D. Adam Smith
 
Title: Assistant Secretary


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
ELK HILLS POWER, LLC
 
 
 
By:
/s/ Ivan Gaydarov
 
Name: Ivan Gaydarov
 
Title: Vice President and Treasurer of California Resources Corporation, the Sole Member of California Resource Elk Hills, LLC, its Sole Member


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
TIDELANDS OIL PRODUCTION COMPANY
 
 
 
By:
/s/ Ivan Gaydarov
 
Name: Ivan Gaydarov
 
Title: Vice President and Treasurer of California Resources Tidelands, Inc., its Managing Partner



 
CALIFORNIA RESOURCES COLES LEVEE, LLC
 
 
 
By:
/s/ Ivan Gaydarov
 
Name: Ivan Gaydarov
 
Title: Vice President and Treasurer


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
CALIFORNIA RESOURCES COLES LEVEE, L.P.
 
 
 
By:
/s/ Ivan Gaydarov
 
Name: Ivan Gaydarov
 
Title: Vice President and Treasurer of California Resources Coles Levee, LLC, its General Partner



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
JPMORGAN CHASE BANK, N.A. , as Administrative Agent, Letter of Credit Issuer, Swingline Lender, Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Douglas A. Kravitz
 
 
Name: Douglas A. Kravitz
 
 
Title: Executive Director


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment







 
 
BANK OF AMERICA, N.A. , as Syndication Agent, Letter of Credit Issuer, Swingline Lender, Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Edna Aguilar Mitchell
 
 
Name: Edna Aguilar Mitchell
 
 
Title: Director

Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
CITIBANK, N.A. , as Letter of Credit Issuer, Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Phil Ballard
 
 
Name: Phil Ballard
 
 
Title: Vice President


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
WELLS FARGO BANK, NATIONAL ASSOCIATION , as Letter of Credit Issuer, Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Michael A. Tribolet
 
 
Name: Michael A. Tribolet
 
 
Title: Managing Director


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
CITIGROUP FINANCIAL PRODUCTS INC.,  as Term Loan Lender

 
 
 
 
 
 
 
 
By: /s/ Brian S. Broyles
 
 
Name: Brian S. Broyles
 
 
Title: Authorized Signatory


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD. , as Revolving Lender
 
 
 
 
 
 
 
 
By: /s/ Kevin Sparks
 
 
Name: Kevin Sparks
 
 
Title: Director



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
U.S. BANK NATIONAL ASSOCIATION , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Mike Warren
 
 
Name: Mike Warren
 
 
Title: Senior Vice President



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
MORGAN STANLEY BANK, N.A.,  as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Dmitriy Barskiy
 
 
Name: Dmitriy Barskiy
 
 
Title: Authorized Signatory


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
MORGAN STANLEY SENIOR FUNDING, INC.,  as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Dmitriy Barskiy
 
 
Name: Dmitriy Barskiy
 
 
Title: Vice President


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
HSBC BANK USA, N.A. , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Benjamin Halperin
 
 
Name: Benjamin Halperin
 
 
Title: Managing Director, Oil & Gas


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
HSBC BANK PLC,  as Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Marvin Rose Nick Hunter
 
 
Name: Marvin Rose / Nick Hunter
 
 
Title: Authorized Signatories


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
GOLDMAN SACHS BANK USA , as Revolving Lender
 
 
 
 
 
 
 
 
By: /s/ Ushma Dedhiya
 
 
Name: Ushma Dedhiya
 
 
Title: Authorized Signatory



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
GOLDMAN SACHS LENDING PARTNERS LLC , as Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Ushma Dedhiya
 
 
Name: Ushma Dedhiya
 
 
Title: Authorized Signatory



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
MIZUHO BANK, LTD. , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Leon Mo
 
 
Name: Leon Mo
 
 
Title: Authorized Signatory



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
BANK OF NOVA SCOTIA , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Mark Sparrow
 
 
Name: Mark Sparrow
 
 
Title: Director



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
ROYAL BANK OF CANADA, As Term Loan Lender

 
 
 
 
 
By: /s/ Nicholas J. Woyevodsky
 
Name: Nicholas J. Woyevodsky
 
Title: Attorney-in-Fact Royal Bank of Canada



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
PNC BANK, NATIONAL ASSOCIATION , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Christopher B. Gribble
 
 
Name: Christopher B. Gribble
 
 
Title: Senior Vice President



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
BRANCH BANKING AND TRUST COMPANY , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Robert Kret
 
 
Name: Robert Kret
 
 
Title: AVP



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
DNB CAPITAL LLC , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Byron Cooley
 
 
Name: Byron Cooley
 
 
Title: Senior Vice President

 
 
By: /s/ James Grubb
 
 
Name: James Grubb
 
 
Title: Vice President



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
THE BANK OF NEW YORK MELLON , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Peter W. Helt
 
 
Name: Peter W. Helt
 
 
Title: Managing Partner



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
SUMITOMO MITSUI BANKING CORPORATION , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Ryo Suzuki
 
 
Name: Ryo Suzuki
 
 
Title: General Manager



Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
INTESA SANPAOLO S.P.A., NEW YORK BRANCH , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ Manuela Insana
 
 
Name: Manuela Insana
 
 
Title: Vice President – Relationship Manager
 
 
 
 
 
By: /s/ Francesco DiMario
 
 
Name: Francesco DiMario
 
 
Title: First Vice President – Head of Credit


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






 
 
KEYBANK NATIONAL ASSOCIATION , as Revolving Lender and Term Loan Lender
 
 
 
 
 
 
 
 
By: /s/ John Dravenstott
 
 
Name: John Dravenstott
 
 
Title: Vice President


Signature Page
CALIFORNIA RESOURCES CORPORATION – Sixth Amendment






IMAGE0A03.JPG
Exhibit 99.1
NEWS RELEASE 
For immediate release


California Resources Corporation Announces
Fourth Quarter 2016 and Year End Results,
2016 Reserves and 2017 Capital Plan


LOS ANGELES, February 16, 2017 – California Resources Corporation (NYSE:CRC), an independent California-based oil and gas exploration and production company, today reported a net loss of $77 million or $1.83 per diluted share for the fourth quarter of 2016. For the full year of 2016 net income was $279 million or $6.76 per diluted share, compared with a net loss of $3.6 billion or $92.79 per diluted share for the same period of 2015. Additionally, CRC announced 2016 reserves of 568 million barrels of oil equivalent (BOE) and 2017 capital investment plans of $300 million.
Adjusted EBITDAX 1 for the fourth quarter and the full year of 2016 was $168 million and $616 million, respectively, compared with $226 million and $906 million for the fourth quarter and the full year of 2015. CRC had annual operating cash flow of $130 million in 2016 and capital investments of $75 million. This financial discipline allowed CRC to generate $49 million of free cash flow after working capital 1 .

Highlights Include:
•
Received sixth bank amendment removing capital investment limitations and allowing additional joint ventures, among other changes
•
Initial 2017 capital investment plan of $300 million
•
2016 capital investment of $75 million with only $31 million of drilling and workover capital
•
Quarterly production of 135,000 BOE per day
◦
A 2.2% sequential decline
◦
A 10% year-over-year decline, excluding PSC effects
•
Annual production of 140,000 BOE per day
•
Annual production costs down 16% from prior year
•
Annual operating cash flow of $130 million
•
2016 Annual free cash flow 2 after working capital of $49 million
•
2016 Organic reserve replacement ratio of 71% with minimal drilling and workover capital
•
2016 Adjusted Organic F&D costs of $3.42 per BOE 3 excluding price adjustments

1,2 For explanations of how we calculate and use Adjusted Net Loss (non-GAAP) and Adjusted EBITDAX (non-GAAP) and reconciliations of net income / (loss) (GAAP) and net cash provided by operating activities (GAAP) to Adjusted EBITDAX and free cash flow after working capital (non-GAAP), please see Attachments 2 and 3.
3 See calculation of F&D on attachment 4.

Page 1


Todd Stevens, President and Chief Executive Officer, said, "We are pleased with our 2016 performance as we strengthened our balance sheet, continued to live within our cash flows, managed our base production to a minimal decline and increased our probable and possible reserves significantly. These achievements reflect the diligence of our team as well as the resiliency of our operations and complementary infrastructure.
"Our planned 2017 capital budget of about $300 million should allow us to increase activity, enhance margins and return to a growth profile beginning in the second half of the year. Additionally, we expect to further expand our actionable inventory. We are pleased to have received our sixth bank amendment which removed capital investment limitations. We will continue to align our investments with our cash flow."

Fourth Quarter Results
For the fourth quarter of 2016, CRC reported a net loss of $77 million or $1.83 per diluted share, compared with a net loss of $3.3 billion or $85.47 per diluted share for the same period of 2015. The 2016 quarter reflected slightly lower realized oil prices including the effect of settled hedges. Compared to the prior year period, the 2016 quarter also reflected higher realized NGL and natural gas prices and lower costs, partially offset by lower volumes, while the 2015 quarter included a non-cash, after-tax impairment charge of $2.9 billion ($4.9 billion pre-tax) and other items. The fourth quarter 2016 adjusted net loss was $74 million or $1.76 per diluted share, compared with an adjusted net loss of $77 million or $2.01 per diluted share for the same period of 2015. The 2016 adjusted net loss excluded $40 million of non-cash derivative losses on outstanding hedges, $12 million of net gains on the early extinguishment of certain of the Company's notes, and $25 million of net gains from other miscellaneous, infrequent items. The 2015 adjusted net loss excluded the impairment charge described above, a $294 million valuation allowance for deferred assets and other after-tax write-offs of $36 million largely reflecting the impact of lower prices on other assets.
Adjusted EBITDAX for the fourth quarter of 2016 was $168 million, compared to $226 million for the same period of 2015.
Total daily production volumes averaged 135,000 barrels of oil equivalent (BOE) for the fourth quarter of 2016, compared with 155,000 BOE for the fourth quarter of 2015, a decrease of less than 13 percent, which is within CRC's estimated base production decline range. This decrease included effects of production sharing contracts (or "PSC") of 4,000 BOE per day. Excluding this PSC effect, the year-over-year quarterly decline would have been 10 percent. The fourth quarter 2016 production decline continued to reflect management's decision to withhold development capital and to selectively defer workover and downhole maintenance activity in the early part of the year. Due to the improved commodity price environment in the second half of the year, the Company began increasing its activity levels, particularly in the fourth quarter, resulting in lower quarterly sequential declines. In the fourth quarter of 2016, realized crude oil prices, including the effect of settled hedges, decreased $0.40 per barrel to $45.48 per barrel from $45.88 per barrel in the prior year comparable quarter. Settled hedges reduced realized crude oil prices by $1.12 per barrel in the fourth quarter of 2016, while increasing the fourth quarter 2015 realized prices by $6.47 per barrel. Realized NGL prices increased 48 percent to $28.99 per barrel from $19.56 per barrel in the fourth quarter of 2015. Realized natural gas prices increased 14 percent to $2.79 per thousand cubic feet (Mcf), compared with $2.44 per Mcf in the same period of 2015. The fourth quarter 2015 realized natural gas prices included $0.16 per Mcf from settled hedges.

Page 2


Production costs for the fourth quarter of 2016 were $217 million or $17.50 per BOE, compared with $221 million or $15.51 per BOE for the fourth quarter of 2015, a 2-percent reduction on an absolute dollar basis. The decrease was driven by well servicing efficiencies and lower energy costs. The fourth quarter of 2016 also reflected $10 million in higher compensation costs than the comparable 2015 quarter. General and administrative (G&A) expenses were $62 million or $5.00 per BOE for the fourth quarter of 2016, compared with $64 million or $4.48 per BOE for the fourth quarter of 2015. The decrease in total G&A expenses reflects employee and contractor cost-reduction initiatives offset by higher employee compensation resulting from a significant increase in the stock price in the fourth quarter of 2016. Adjusted G&A expenses for the fourth quarter of 2016 were $61 million or $4.92 per BOE, compared with $69 million or $4.80 per BOE for the fourth quarter of 2015. Taxes other than on income of $26 million for the fourth quarter of 2016 were $4 million lower than the same period of 2015. Exploration expenses of $10 million for the fourth quarter of 2016 were $3 million higher than the same period of 2015.
Capital investment in the fourth quarter of 2016 totaled $31 million, of which $20 million was directed to drilling and capital workovers.

Full Year 2016 Results
For the full year of 2016, CRC reported net income of $279 million or $6.76 per diluted share, compared with a net loss of $3.6 billion or $92.79 per diluted share in 2015. The 2016 income reflected the net gains from the early extinguishment of the Company's notes and divestiture of assets as well as lower costs, partially offset by lower oil and natural gas prices and volumes and non-cash derivative losses on outstanding hedges, while 2015 also included the fourth-quarter impairment charge and other items. The 2016 adjusted net loss was $317 million or $7.85 per diluted share, compared with an adjusted net loss of $311 million or $8.12 per diluted share for 2015. The 2016 adjusted net loss excluded $805 million of net gains on the early extinguishment of the Company's notes, $283 million of non-cash derivative losses on outstanding hedges, a $63 million benefit from a deferred tax valuation allowance adjustment, a $20 million charge resulting from employee reductions that were made during the year, a $30 million gain from asset divestitures, a $12 million write-off of deferred financing costs related to the retirement of the Company's notes and $13 million net gains from other miscellaneous, infrequent charges. The 2015 adjusted net loss excluded a non-cash, after-tax impairment charge of $2.9 billion ($4.9 billion pre-tax), a $294 million valuation allowance for deferred assets, $52 million of non-cash derivative gains, a $71 million charge reflecting the effect of prices on other assets, $67 million of severance and early retirement costs, and $19 million net from other infrequent net charges and related tax adjustments.
Adjusted EBITDAX for the full year of 2016 was $616 million, compared to $906 million in the prior-year period.
Total daily production volumes averaged 140,000 BOE for the full year of 2016, compared with 160,000 BOE for the full year of 2015, a 12.5-percent decrease which is within CRC's estimated base production decline range. Excluding the PSC effects, the annual decline would have been under 12 percent. CRC's year-over-year average oil production was 91,000 barrels per day for the full year of 2016, a decrease of under 13 percent, or 13,000 barrels per day, compared with the same period of 2015. NGL production decreased by 11 percent to 16,000 barrels per day and natural gas production decreased by 14 percent to 197 million cubic feet (MMcf) per day.

Page 3


Realized crude oil prices, including the effect of settled hedges, decreased 15 percent to $42.01 per barrel for 2016 from $49.19 per barrel in 2015. Hedges contributed $2.29 per barrel to realized crude oil prices for 2016, compared with $2.04 for the same period of 2015. Realized NGL prices increased 14 percent to $22.39 per barrel for 2016 from $19.62 per barrel in 2015. Realized natural gas prices decreased 14 percent to $2.28 per Mcf for 2016, compared with $2.66 per Mcf in the same period of 2015.
Production costs for 2016 were $800 million or $15.61 per BOE, compared with $951 million or $16.30 per BOE for the same period in 2015, a 16-percent reduction on an absolute dollar basis. The decrease reflected cost reductions throughout CRC's operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, as well as lower workover and downhole maintenance activity in 2016. G&A expenses were $248 million or $4.84 per BOE for the full year of 2016, compared with $354 million or $6.07 per BOE for the same period of 2015, reflecting employee and contractor cost-reduction initiatives and greater severance and early retirement costs included in the prior-year period. Adjusted G&A expenses were $228 million or $4.45 per BOE for the full year of 2016, compared with $287 million or $4.92 per BOE for the same period of 2015. Adjusted G&A expenses for both years excluded severance and early retirement. Exploration expenses of $23 million for the full year of 2016 were $13 million lower than the same period of 2015. Taxes other than on income were $144 million for 2016, compared to $180 million for 2015. The decrease was largely due to a reduction in property taxes.
Consistent with our operating tenet of living within cash flow, the Company generated $130 million of operating cash flow and free cash flow after capital of $49 million for the full year of 2016.

2016 Proved Reserves and PV-10 Value
CRC’s proved reserves estimates for the year ended December 31, 2016, as audited by Ryder Scott, were 568 million BOE, consisting of 72 percent oil and 71 percent proved developed volumes. The Company achieved a total organic reserves replacement ratio (RRR) (4) of 71 percent of 2016 production, excluding price adjustments. Price-related adjustments reduced overall reserves by 60 million BOE. Volumes that have been removed from the reserves base due to lower prices are expected to return to CRC's proved base at higher prices of crude oil.

Summary of Changes in Proved Reserves (Million BOE)
Balance at December 31, 2015
644
Revision of Previous Estimates (Performance-Related)
  13
Extensions and Discoveries
  20
Improved Recovery
    3
 
 
Divestiture of Proved Reserves
  (1)
Price-Related Revisions
 (60)
Production
 (51)
Balance at December 31, 2016
 568*
 
 
2016 Organic F&D cost, excluding price adjustments (5)
$3.42
*Calculated using the first-day-of-the-month twelve-month average Brent oil price of $42.90 per barrel and Henry Hub price of $2.48 per million British Thermal units (BTU) for natural gas, before adjustments for gravity, quality and transportation costs, in accordance with Securities and Exchange Commission (SEC) guidelines.
4,5 See calculation of RRR and F&D on attachment 4.

Page 4



The present value of CRC's proved reserves as of December 31, 2016 was approximately $2.8 billion, on a pre-tax basis, discounted at 10 percent (PV-10) (6) . The reduction from the prior year amount of $5.1 billion, resulted from a 23-percent and 4-percent decrease in crude oil prices and natural gas prices, respectively. The effect of price decreases was partially offset by reserves additions, cost reductions and efficiencies identified in the Company's life-of-field plans. Utilizing current costs, a flat $55 Brent crude oil price deck and $3.30/Mcf Henry Hub natural gas price, which is similar to the 2015 SEC pricing and the current strip prices, CRC's proved reserves would be approximately 686 million barrels. Using these same assumptions, the PV-10 would be nearly $5.4 billion for proved reserves and $9.7 billion for proved, probable and possible reserves.

6 PV-10 is a non-GAAP financial measure. For a reconciliation to the GAAP standardized measure of discounted future net cash flows, see attachment 4.

Hedging Update
CRC continues to opportunistically add hedges to protect its cash flow, margins and capital program and to maintain liquidity. For example, currently we have hedges in place covering over 45% of our projected first quarter 2017 oil production. See attachment 11 for more details.

Operational Update and 2017 Capital Investment Plan
CRC operated two drilling rigs at year end 2016 with one in the San Joaquin basin and one in the Los Angeles basin. In the fourth quarter, CRC drilled 4 waterflood wells and 17 steamflood wells. By the end of the first quarter of 2017, we anticipate having four rigs running (three in the San Joaquin basin and one in the Los Angeles basin).
Consistent with prior years, CRC expects to align our capital investment with our operational cash flow, and adjust our capital plan accordingly. Based on the current market conditions, CRC will begin the year with a capital investment plan of $300 million, consisting of approximately $150 million for drilling and completions, $50 million for capital work-overs, $50 million for facilities, $25 million for exploration and $25 million primarily for mechanical integrity projects. Our 2017 development program will focus primarily on our core fields- Elk Hills, Wilmington, Kern Front, Buena Vista, and the delineation of Kettleman North Dome. We have developed a dynamic plan which can be scaled up or down depending on the price environment. For 2017, we have action plans that allow us to reduce our capital investment to under $100 million or increase it to as high as $500 million based on conditions during the year. Going forward, we will continue to focus on identifying, evaluating and pursuing value creation opportunities that strengthen our balance sheet and reduce our financial leverage.

CRC Analyst Day and Site Tour
We are pleased to announce that CRC is hosting a 2017 Analyst Day and Site Tours in the Bakersfield and Long Beach areas in California on March 22-23. Due to the length of the event, logistical considerations and safety requirements, space will be limited. We will be webcasting the formal presentations and will post them to CRC's investor relations page on our website at www.crc.com. The event will be archived for play later on the day of the presentations.

Page 5


Conference Call Details
To participate in today’s conference call, either dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com , fifteen minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call a t http://dpregister.com/10097714. A digital replay of the conference call will be archived for approximately 30 days and supplemental slides for the conference call will be available online in Investor Relations at www.crc.com.

About California Resources Corporation
California Resources Corporation is the largest oil and natural gas exploration and production company in California on a gross-operated basis. The Company operates its world class resource base exclusively within the State of California, applying integrated infrastructure to gather, process and market its production. Using advanced technology, California Resources Corporation focuses on safely and responsibly supplying affordable energy for California by Californians.

Forward-Looking Statements
This presentation contains 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 include those regarding our expectations as to our future:
•
financial position, liquidity, cash flows, and results of operations
•
business prospects
•
transactions and projects
•
operating costs
•
operations and operational results including production, hedging, capital investment and expected VCI
•
budgets and maintenance capital requirements
•
reserves
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. Factors (but not necessarily all the factors) that could cause results to differ include:
•
commodity price changes
•
debt limitations on our financial flexibility
•
insufficient cash flow to fund planned investment
•
inability to enter desirable transactions including asset sales and joint ventures
•
legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products
•
unexpected geologic conditions
•
changes in business strategy
•
inability to replace reserves
•
insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors
•
inability to enter efficient hedges

Page 6


•
equipment, service or labor price inflation or unavailability
•
availability or timing of, or conditions imposed on, permits and approvals
•
lower-than-expected production, reserves or resources from development projects or acquisitions or higher-than-expected decline rates
•
disruptions due to accidents, mechanical failures, transportation constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
•
factors discussed in “Risk Factors” in our Annual Report on Form 10-K available on our website at crc.com.
Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
We have provided internally generated estimates of PV-10 for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of December 31, 2016 in this presentation, with each category of reserves estimated in accordance with SEC guidelines and definitions, though we have not reported all such estimates to the SEC. As used in this presentation:
Probable reserves . We use deterministic methods to estimate probable reserve quantities, and when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.
Possible reserves . We use deterministic methods to estimate possible reserve quantities, and when deterministic methods are used to estimate possible reserve quantities, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.
The SEC prohibits companies from aggregating proved, probable and possible reserves estimated using deterministic estimation methods in filings with the SEC due to the different levels of certainty associated with each reserve category.
Actual quantities that may be ultimately recovered from our interests may differ substantially from the estimates in this release. Factors affecting ultimate recovery include the scope of our ongoing drilling and workover program, which will be directly affected by commodity prices, the availability of capital, regulatory approvals, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints and other factors; actual drilling results, which may be affected by geological, mechanical and other factors that determine recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital.
    
-0-
Contacts:

Scott Espenshade (Investor Relations)
818-661-6010
Scott.Espenshade@crc.com
Margita Thompson (Media)
818-661-6005
Margita.Thompson@crc.com  

Page 7


Attachment 1
SUMMARY OF RESULTS
 
 
 
 
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
($ and shares in millions, except per share amounts)
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
 
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues and Other
 
 
 
 
 
 
 
 
 
Oil and gas net sales
 
$
464

 
$
447

 
$
1,621

 
$
2,134

 
Net derivative (losses) gains
 
(49
)
 
83

 
(206
)
 
133

 
Other revenue
 
37

 
36

 
132

 
136

 
   Total revenues and other
 
452

 
566

 
1,547

 
2,403

 
 
 
 
 
 
 
 
 
 
 
Costs and Other
 
 
 
 
 
 
 
 
 
Production costs
 
217

 
221

 
800

 
951

 
General and administrative expenses
 
62

 
64

 
248

 
354

 
Depreciation, depletion and amortization
 
137

 
247

 
559

 
1,004

 
Asset impairments
 
—

 
4,852

 
—

 
4,852

 
Taxes other than on income
 
26

 
30

 
144

 
180

 
Exploration expense
 
10

 
7

 
23

 
36

 
Other expenses, net
 
3

 
94

 
79

 
168

 
  Total costs and other
 
455

 
5,515

 
1,853

 
7,545

 
 
 
 
 
 
 
 
 
 
 
Operating Loss
 
(3
)
 
(4,949
)
 
(306
)
 
(5,142
)
 
 
 
 
 
 
 
 
 
 
 
Non-Operating (Loss) Income
 
 
 
 
 
 
 
 
 
Interest and debt expense, net
 
(85
)
 
(82
)
 
(328
)
 
(326
)
 
Net gains on early extinguishment of debt
 
12

 
20

 
805

 
20

 
Other non-operating (expense) income
 
(1
)
 
(28
)
 
30

 
(28
)
 
 
 
 
 
 
 
 
 
 
 
(Loss) Income Before Income Taxes
 
(77
)
 
(5,039
)
 
201

 
(5,476
)
 
Income tax benefit
 
—

 
1,757

 
78

 
1,922

 
Net (Loss) Income
 
$
(77
)
 
$
(3,282
)
 
$
279

 
$
(3,554
)
 
 
 
 
 
 
 
 
 
 
 
EPS - diluted
 
$
(1.83
)
 
$
(85.47
)
 
$
6.76

 
$
(92.79
)
 
 
 
 
 
 
 
 
 
 
 
Adjusted Net Loss
 
$
(74
)
 
$
(77
)
 
$
(317
)
 
$
(311
)
 
Adjusted EPS - diluted
 
$
(1.76
)
 
$
(2.01
)
 
$
(7.85
)
 
$
(8.12
)
 
 
 
 
 
 
 
 
 
 
 
Weighted average diluted shares outstanding
 
42.1

 
38.4

 
40.4

 
38.3

 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDAX
 
$
168

 
$
226

 
$
616

 
$
906

 
Effective tax rate
 
0%

 
35
%
 
(39)%

 
35
%
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash (used) provided by operating activities
 
$
(15
)
 
$
(9
)
 
$
130

 
$
403

 
Net cash used by investing activities
 
$
(30
)
 
$
(215
)
 
$
(61
)
 
$
(757
)
 
Net cash (used) provided by financing activities
 
$
47

 
$
232

 
$
(69
)
 
$
352

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data:
 
December 31,
 
December 31,
 
 
 
 
 
 
 
2016
 
2015
 
 
 
 
 
Total current assets
 
$
425

 
$
438

 
 
 
 
 
Property, plant and equipment, net
 
$
5,885

 
$
6,312

 
 
 
 
 
Total current liabilities
 
$
726

 
$
605

 
 
 
 
 
Long-term debt, principal amount
 
$
5,168

 
$
6,043

 
 
 
 
 
Total equity
 
$
(557
)
 
$
(916
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding shares as of
 
42.5

 
38.8

 
 
 
 
 

Page 8


Attachment 2
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
 
Our results of operations can include the effects of unusual and infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore, management uses a measure called "adjusted net income / (loss)" and a measure it calls "adjusted general and administrative expenses" which exclude those items. These non-GAAP 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 income / (loss) and adjusted general and administrative expenses are not considered to be alternatives to net income / (loss) and general and administrative expenses reported in accordance with GAAP.
 
The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted net (loss) income:
 
 
Fourth Quarter
 
Twelve Months
 
($ millions, except per share amounts)
 
2016
 
2015
 
2016
 
2015
 
Net (loss) income
 
$
(77
)
 
$
(3,282
)
 
$
279

 
$
(3,554
)
 
Unusual and infrequent items:
 
 
 
 
 
 
 
 
 
Asset impairments
 
—

 
4,852

 
—

 
4,852

 
Write-down of certain assets
 
—

 
71

 
—

 
71

 
Non-cash derivative losses (gains)
 
40

 
(19
)
 
283

 
(52
)
 
Severance, early retirement and other costs
 
1

 
(5
)
 
20

 
67

 
Refunds, plant turnaround charges and other
 
(27
)
 
5

 
(13
)
 
11

 
Net gains on early extinguishment of debt
 
(12
)
 
(20
)
 
(805
)
 
(20
)
 
Debt issuance costs
 
—

 
28

 
—

 
28

 
Loss (gain) from asset divestitures
 
1

 
—

 
(30
)
 
—

 
Adjusted income items before interest and taxes
 
3

 
4,912

 
(545
)
 
4,957

 
 
 
 
 
 
 
 
 
 
 
Deferred debt issuance costs write-off
 
—

 
—

 
12

 
—

 
Adjustments for valuation allowance on deferred tax assets
 
—

 
294

 
(63
)
(a)  
294

 
Tax effects of these items and related adjustments
 
—

 
(2,001
)
 
—

 
(2,008
)
 
Total
 
$
3

 
$
3,205

 
$
(596
)
 
$
3,243

 
Adjusted net loss
 
$
(74
)
 
$
(77
)
 
$
(317
)
 
$
(311
)
 
 
 
 
 
 
 
 
 
 
 
Net (loss) income per diluted share
 
$
(1.83
)
 
$
(85.47
)
 
$
6.76

 
$
(92.79
)
 
Adjusted net loss per diluted share
 
$
(1.76
)
 
$
(2.01
)
 
$
(7.85
)
 
$
(8.12
)
 
(a) Amount represents the out-of-period portion of the valuation allowance reversal.
 
 
 
 
 
 
 
 
 
 
 
DERIVATIVES GAINS AND LOSSES
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
($ millions)
 
2016
 
2015
 
2016
 
2015
 
Non-cash derivative losses (gains)
 
$
40

 
$
(19
)
 
$
283

 
$
(52
)
 
Payments (proceeds) from settled derivatives
 
9

 
(64
)
 
(77
)
 
(81
)
 
Net derivative losses (gains)
 
$
49

 
$
(83
)
 
$
206

 
$
(133
)
 
 
 
 
 
 
 
 
 
 
 
FREE CASH FLOW
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
($ millions)
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
 
Operating cash flow
 
$
(15
)
 
$
(9
)
 
$
130

 
$
403

 
   Capital investment
 
(31
)
 
(78
)
 
(75
)
 
(401
)
 
   Changes in capital accruals
 
(1
)
 
(3
)
 
(6
)
 
(205
)
 
Free cash flow (after working capital)
 
$
(47
)
 
$
(90
)
 
$
49

 
$
(203
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Page 9


 
 
 
 
 
 
 
 
 
 
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
($ millions)
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
 
General and administrative expenses
 
$
62

 
$
64

 
$
248

 
$
354

 
   Severance, early retirement and other costs
 
(1
)
 
5

 
(20
)
 
(67
)
 
Adjusted general and administrative expenses
 
$
61

 
$
69

 
$
228

 
$
287

 






















Page 10


 
Attachment 3
 
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
 
We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other 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, the investment community and our lenders. While adjusted EBITDAX is a non-GAAP measure, the amounts included in the calculation of adjusted EBITDAX were computed in accordance with U.S. generally accepted accounting principles (GAAP). This measure is a material component of certain of our financial covenants under our first-lien, first-out credit facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
 
The following tables present a reconciliation of the GAAP financial measures of net (loss) / income and net cash (used) / provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX:
 
 
 
 
 
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
 
($ millions)
 
2016
 
2015
 
2016
 
2015
 
 
Net (loss) income
 
$
(77
)
 
$
(3,282
)
 
$
279

 
$
(3,554
)
 
 
Interest and debt expense
 
85

 
82

 
328

 
326

 
 
Income tax benefit
 
—

 
(1,757
)
 
(78
)
 
(1,922
)
 
 
Depreciation, depletion and amortization
 
137

 
247

 
559

 
1,004

 
 
Exploration expense
 
10

 
7

 
23

 
36

 
 
Adjusted income items before interest and taxes (a)
 
3

 
4,912

 
(545
)
 
4,957

 
 
Other items
 
10

 
17

 
50

 
59

 
 
Adjusted EBITDAX
 
168

 
226

 
616

 
906

 
 
 
 
 
 
 
 
 
 
 
 
 
Net cash (used) provided by operating activities
 
$
(15
)
 
$
(9
)
 
$
130

 
$
403

 
 
Cash Interest
 
140

 
111

 
384

 
359

 
 
Exploration expenditures
 
7

 
7

 
20

 
27

 
 
Other changes in operating assets and liabilities
 
63

 
112

 
95

 
106

 
 
Refunds, plant turnaround charges and other
 
(27
)
 
5

 
(13
)
 
11

 
 
Adjusted EBITDAX
 
168

 
226

 
616

 
906

 
 
 
 
 
 
 
 
 
 
 
 
 
(a) See Attachment 2.
 


Page 11


 
Attachment 4
 
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The following table presents a reconciliation of the non-GAAP financial measure of PV-10 to the GAAP financial measure of standardized measure of discounted future net cash flows:
 
 
 
 
 
 
 
 
 
 
 
 
PV-10 and Standardized Measure ($ millions)
 
 
 
 
 
2016
 
 
 
 
PV-10 of proved reserves (1)
 
 
 
 
 
$
2,848

 
 
 
 
Present value of future income taxes discounted at 10%
 
 
 
 
 
(181
)
 
 
 
 
Standardized measure of discounted future net cash flows
 
 
 
 
 
$
2,667

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserves bases and the reserves bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Organic Reserve Replacement Ratio (2)
 
 
 
 
 
2016
 
 
 
 
Proved reserves added - MMBOE
 
 
 
 
 
 
 
 
 
 
Extensions and Discovery
 
 
 
 
 
20

 
 
 
 
Improved Recovery
 
 
 
 
 
3

 
 
 
 
Revisions related to performance
 
 
 
 
 
13

 
 
 
 
Total (A)
 
 
 
 
 
36

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Production in 2016 - MMBOE (B)
 
 
 
 
 
51

 
 
 
 
Organic Reserves Replacement Ratio (A)/(B)
 
 
 
 
 
71
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(2) The organic reserves replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery, and performance-related provisions, divided by oil-equivalent production. Approximately 89% of the additions for 2016 are proved undeveloped. There is no guarantee that historical sources of reserves additions will continue as many factors could cause unforeseen results, including geology, government regulations and permits, commodity prices, the availability of capital, the effectiveness of development plans and other factors that affect reserves additions and are partially or fully outside management's control. Management uses this measure to gauge results of its capital allocation.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Organic Finding and Development Costs (3)
 
 
 
 
 
2016
 
 
 
 
Organic costs incurred - in millions (A)
 
$ 123 (4)

 
 
 
 
Proved Reserves Added - MMBOE (B)
 
            36 (5)

 
 
 
 
Organic Finding and Development Costs - $/BOE (A)/(B)
 
$
3.42

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(3) We calculate organic finding and development costs by dividing the costs incurred for the year from the capital program (including development, including asset retirement obligations, and exploration costs, but excluding acquisitions) by the amount of oil-equivalent proved reserves added in the same year from improved recovery, extensions and discoveries and performance-related revisions (excluding acquisitions and price-related revisions). We believe that reporting our finding and development costs can aid investors in their evaluation of our ability to add proved reserves at a reasonable cost but is not a substitute for GAAP disclosures. Various factors, including timing differences and effects of commodity price changes, can cause finding and development costs to reflect costs associated with particular reserves imprecisely. For example, we will need to make more investments in order to develop the proved undeveloped reserves added during the year and any future revisions may change the actual measure from that presented above. In addition, part of the 2016 costs were incurred to convert proved undeveloped reserves from prior years to proved developed reserves. Our calculations of finding and development costs may not be comparable to similar measures provided by other companies. We have not estimated future costs expected for the reserves added or removed costs related to reserves added in prior periods.
 
 
(4) Includes development and exploration costs, as well as asset retirement obligations.
 
(5) Includes performance revisions.


Page 12


Attachment 5
ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS
 
 
 
($ millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 4th Quarter Adjusted Net Loss
 
$
(77
)
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
Price - Oil
 
(2
)
 
 
 
 
 
 
 
Price - NGLs
 
15

 
 
 
 
 
 
 
Price - Natural Gas
 
7

 
 
 
 
 
 
 
Volume
 
(47
)
 
 
 
 
 
 
 
Production cost rate
 
(4
)
 
 
 
 
 
 
 
DD&A rate
 
91

 
 
 
 
 
 
 
Exploration expense
 
(3
)
 
 
 
 
 
 
 
Interest expense
 
(3
)
 
 
 
 
 
 
 
Adjusted general & administrative expenses
 
8

 
 
 
 
 
 
 
Income tax
 
(50
)
 
 
 
 
 
 
 
All Others
 
(9
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016 4th Quarter Adjusted Net Loss
 
$
(74
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Twelve Month Adjusted Net Loss
 
$
(311
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Price - Oil
 
(283
)
 
 
 
 
 
 
 
Price - NGLs
 
19

 
 
 
 
 
 
 
Price - Natural Gas
 
(31
)
 
 
 
 
 
 
 
Volume
 
(116
)
 
 
 
 
 
 
 
Production cost rate
 
122

 
 
 
 
 
 
 
DD&A rate
 
376

 
 
 
 
 
 
 
Exploration expense
 
13

 
 
 
 
 
 
 
Interest expense
 
10

 
 
 
 
 
 
 
Adjusted general & administrative expenses
 
59

 
 
 
 
 
 
 
Income tax
 
(193
)
 
 
 
 
 
 
 
All Others
 
18

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016 Twelve Month Adjusted Net Loss
 
$
(317
)
 
 
 
 
 
 
 

Page 13


 
 
 
 
 
 
 
 
 
Attachment 6
CAPITAL INVESTMENTS
 
 
 
 
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
($ millions)
 
2016
 
2015
 
2016
 
2015
 
Capital Investments:
 
 
 
 
 
 
 
 
 
Conventional
 
$
22

 
$
62

 
$
41

 
$
328

 
Unconventional
 
6

 
8

 
12

 
25

 
Exploration
 
1

 
—

 
1

 
17

 
  Other (a)
 
2

 
8

 
21

 
31

 
 
 
$
31

 
$
78

 
$
75

 
$
401

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Twelve months of 2016 includes $19 million of capital incurred for the planned turnaround at the Elk Hills Power Plant, of which payment of $10 million is deferred to future periods.

Page 14


 
 
 
 
 
 
 
 
 
Attachment 7
 
PRODUCTION STATISTICS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
 
Net Oil, NGLs and Natural Gas Production Per Day
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbl/d)
 
 
 
 
 
 
 
 
 
 
  San Joaquin Basin
 
55

 
61

 
57

 
64

 
 
  Los Angeles Basin
 
27

 
35

 
29

 
34

 
 
  Ventura Basin
 
5

 
6

 
5

 
6

 
 
  Sacramento Basin
 
—

 
—

 
—

 
—

 
 
  Total
 
87

 
102

 
91

 
104

 
 
 
 
 
 
 
 
 
 
 
 
 
NGLs (MBbl/d)
 
 
 
 
 
 
 
 
 
 
  San Joaquin Basin
 
14

 
17

 
15

 
17

 
 
  Los Angeles Basin
 
—

 
—

 
—

 
—

 
 
  Ventura Basin
 
1

 
1

 
1

 
1

 
 
  Sacramento Basin
 
—

 
—

 
—

 
—

 
 
  Total
 
15

 
18

 
16

 
18

 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas (MMcf/d)
 
 
 
 
 
 
 
 
 
 
  San Joaquin Basin
 
152

 
161

 
150

 
172

 
 
  Los Angeles Basin
 
1

 
2

 
3

 
2

 
 
  Ventura Basin
 
8

 
9

 
8

 
11

 
 
  Sacramento Basin
 
34

 
40

 
36

 
44

 
 
  Total
 
195

 
212

 
197

 
229

 
 
 
 
 
 
 
 
 
 
 
 
 
Total Barrels of Oil Equivalent (MBoe/d)  (a)
 
135

 
155

 
140

 
160

 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Natural gas volumes have been converted to BOE based on the equivalence of energy content between six Mcf of natural gas and one Bbl 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 year ended December 31, 2016, the average prices of Brent oil and NYMEX natural gas were $45.04 per Bbl and $2.42 per MMBtu, respectively, resulting in an oil-to-gas price ratio of approximately 19 to 1.
 
 

Page 15


 
 
 
 
 
 
 
 
Attachment 8
PRICE STATISTICS
 
 
 
 
 
 
 
 
 
 
 
Fourth Quarter
 
Twelve Months
 
 
 
2016
 
2015
 
2016
 
2015
 
Realized Prices
 
 
 
 
 
 
 
 
 
  Oil with hedge ($/Bbl)
 
$
45.48

 
$
45.88

 
$
42.01

 
$
49.19

 
  Oil without hedge ($/Bbl)
 
$
46.60

 
$
39.41

 
$
39.72

 
$
47.15

 
 
 
 
 
 
 
 
 
 
 
  NGLs ($/Bbl)
 
$
28.99

 
$
19.56

 
$
22.39

 
$
19.62

 
 
 
 
 
 
 
 
 
 
 
  Natural gas with hedge ($/Mcf)
 
$
2.79

 
$
2.44

 
$
2.28

 
$
2.66

 
  Natural gas without hedge ($/Mcf)
 
$
2.79

 
$
2.28

 
$
2.28

 
$
2.61

 
 
 
 
 
 
 
 
 
 
 
Index Prices
 
 
 
 
 
 
 
 
 
  Brent oil ($/Bbl)
 
$
51.13

 
$
44.71

 
$
45.04

 
$
53.64

 
  WTI oil ($/Bbl)
 
$
49.29

 
$
42.18

 
$
43.32

 
$
48.80

 
  NYMEX gas ($/MMBtu)
 
$
2.95

 
$
2.44

 
$
2.42

 
$
2.75

 
 
 
 
 
 
 
 
 
 
 
Realized Prices as Percentage of Index Prices
  Oil with hedge as a percentage of Brent
 
89
%
 
103
%
 
93
%
 
92
%
 
  Oil without hedge as a percentage of Brent
 
91
%
 
88
%
 
88
%
 
88
%
 
 
 
 
 
 
 
 
 
 
 
  Oil with hedge as a percentage of WTI
 
92
%
 
109
%
 
97
%
 
101
%
 
  Oil without hedge as a percentage of WTI
 
95
%
 
93
%
 
92
%
 
97
%
 
 
 
 
 
 
 
 
 
 
 
  NGLs as a percentage of Brent
 
57
%
 
44
%
 
50
%
 
37
%
 
  NGLs as a percentage of WTI
 
59
%
 
46
%
 
52
%
 
40
%
 
 
 
 
 
 
 
 
 
 
 
  Natural gas with hedge as a percentage of NYMEX
 
95
%
 
100
%
 
94
%
 
97
%
 
  Natural gas without hedge as a percentage of NYMEX
 
95
%
 
93
%
 
94
%
 
95
%
 

Page 16


 
 
 
Attachment 9
2017 FIRST QUARTER GUIDANCE
 
 
 
 
 
 
 
Anticipated Realizations Against the Prevailing Index Prices for Q1 2017 (a)
 
Oil
88% to 92% of Brent
 
 
NGLs
50% to 55% of Brent
 
 
Natural Gas
90% to 94% of NYMEX
 
 
 
 
 
 
2017 First Quarter Production, Capital and Income Statement Guidance
 
Production
128 to 133 MBOE per day
 
 
Capital
$60 million to $70 million
 
 
Production costs
$18.10 to $18.60 per BOE
 
 
Adjusted general and administrative expenses
$5.35 to $5.65 per BOE
 
 
Depreciation, depletion and amortization
$11.65 to $11.95 per BOE
 
 
Taxes other than on income
$31 million to $35 million
 
 
Exploration expense
$5 million to $9 million
 
 
Interest expense (b)
$81 million to $85 million
 
 
Cash Interest (b)
$52 million to $56 million
 
 
Income tax expense rate
0%
 
 
Cash tax rate
0%
 
 
 
 
 
 
 
On Income
On Cash
 
Pre-tax First Quarter Price Sensitivities
 
 
 
$1 change in Brent index - Oil (at price above $56.00) (c)
$3.5 million
$3.5 million
 
$1 change in Brent index - NGLs
$0.8 million
$0.8 million
 
$0.50 change in NYMEX - Gas
$3.2 million
$3.2 million
 
 
 
 
 
 
 
 
 
First Quarter Volumes Sensitivities
 
 
 
$1 change in the Brent index (d)
200 Bbl/d
 
 
 
 
 
 
(a) Realizations exclude hedge effects.
(b) Interest expense includes the amortization of the deferred gain that resulted from the December 2015 debt exchange. Cash interest for the quarter is lower than interest expense due to the timing of interest payments.
(c) At a Brent index price between $49.00 and $56.00 the sensitivity goes up to $4.4 million.
(d) Reflects the effect of production sharing type contracts in our Wilmington field operations.
 

Page 17


 
 
 
 
 
 
 
 
 
 
Attachment 10
FULL YEAR DRILLING ACTIVITY
 
 
 
 
 
 
 
 
 
 
 
 
San Joaquin
 
Los Angeles
 
Ventura
 
Sacramento
 
 
Wells Drilled (Net)
 
Basin
 
Basin
 
Basin
 
Basin
 
Total
 
 
 
 
 
 
 
 
 
 
 
Development Wells
 
 
 
 
 
 
 
 
 
 
Primary
 
—
 
—
 
—
 
—
 
—
Waterflood
 
3
 
5
 
—
 
—
 
8
Steamflood
 
34
 
—
 
—
 
—
 
34
Unconventional
 
—
 
—
 
—
 
—
 
—
Total
 
37
 
5
 
—
 
—
 
42
 
 
 
 
 
 
 
 
 
 
 
Exploration Wells
 
 
 
 
 
 
 
 
 
 
Primary
 
—
 
—
 
—
 
—
 
—
Waterflood
 
—
 
—
 
—
 
—
 
—
Steamflood
 
—
 
—
 
—
 
—
 
—
Unconventional
 
—
 
—
 
—
 
—
 
—
Total
 
—
 
—
 
—
 
—
 
—
 
 
 
 
 
 
 
 
 
 
 
Total Wells
 
37
 
5
 
—
 
—
 
42
 
 
 
 
 
 
 
 
 
 
 
Development Drilling Capital
($ millions)
 
$7
 
$6
 
$—
 
$—
 
$13
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



Page 18


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Attachment 11
 
HEDGING ACTIVITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Q1 2017
 
Q2 2017
 
Q3 2017
 
Q4 2017
 
Q1 2018
 
Q2-Q4 2018
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
Calls:
 
 
 
 
 
 
 
 
 
 
 
 
Barrels per day
12,100
 
 
 
5,000
 
 
 
10,000
 
 

15,000
 
 
15,600
 
 
15,000
 
 
Weighted-average price per barrel
$
56.37

 
 
$
55.05

 
 
$
56.15

 

$
56.12
 
 
$
58.77
 
 
$
58.83
 
 
 
 
 
 
 
 

 
 
 
 
 
 
Puts:
 
 
 
 
 
 

 
 
 
 
 
 
Barrels per day
22,100
 
 

20,000
 
 
 
17,000
 
 

10,000
 
 
 
 
 
 
 
 
Weighted-average price per barrel
$
49.10

 
 
$
50.25

 
 
$
50.88

 
 
$
48.00
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaps:
 
 
 
 
 
 

 
 
 
 
 
 
Barrels per day
20,000
 
 
 
20,000
 
 
 
20,000
 
 

20,000
 
 
 
 
 
 
 
 
Weighted-average price per barrel
$
53.98

 
 
$
53.98

 
 
$
53.98

 

$
53.98
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
The second through fourth quarter 2017 crude oil swaps grant the counterparty a quarterly option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46. The counterparty also has an option to increase volumes by up to 5,000 barrels per day for the second half of the year at a weighted-average Brent price of $61.43.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Page 19


 
 
 
 
 
Attachment 12
 
RESERVES
 
 
 
 
 
 
 
San Joaquin
Los Angeles
Ventura
Sacramento
 
 
As of December 31, 2016
Basin
Basin
Basin
Basin
Total
 
Oil Reserves (in millions of barrels)
 
 
 
 
 
 
Proved Developed Reserves
177
82
20
—
279
 
Proved Undeveloped Reserves
110
16
4
—
130
 
Total
287
98
24
—
409
 
 
 
 
 
 
 
 
NGLs Reserves (in millions of barrels)
 
 
 
 
 
 
Proved Developed Reserves
42
—
2
—
44
 
Proved Undeveloped Reserves
11
—
—
—
11
 
Total
53
—
2
—
55
 
 
 
 
 
 
 
 
Natural Gas Reserves (in billions of cubic feet)
 
 
 
 
 
 
Proved Developed Reserves
410
7
15
68
500
 
Proved Undeveloped Reserves
126
—
—
—
126
 
Total
536
7
15
68
626
 
 
 
 
 
 
 
 
Total Reserves (in millions of barrels of oil equivalent)*
 
 
 
 
 
 
Proved Developed Reserves
287
83
25
11
406
 
Proved Undeveloped Reserves
142
16
4
—
162
 
Total
429
99
29
11
568
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
*Natural gas volumes have been converted to BOE based on the equivalence of energy content between six Mcf of natural gas and one Bbl 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, in 2016, the average prices of Brent oil and NYMEX natural gas were $45.04 per Bbl and $2.42 per MMBtu, respectively, resulting in an oil-to-gas price ratio of approximately 19 to 1.
 
 


Page 20


IMAGE0A01.JPG
Exhibit 99.2
NEWS RELEASE 
For immediate release

California Resources Corporation Announces Joint Venture to Invest $250 Million in Oil & Gas Properties
Los Angeles, February 16, 2017 – California Resources Corporation (NYSE: CRC) announced today a joint venture (JV) with Benefit Street Partners L.L.C. (BSP) to invest in CRC’s oil and gas properties in California, with a focus on development opportunities in multiple CRC producing fields. CRC will operate the properties.
The Joint Venture calls for Benefit Street Partners to invest up to $250 million for development opportunities in both conventional and unconventional assets of CRC in California. BSP will make an initial $50 million investment to be directed toward drilling activities across properties subject to the JV. BSP will make subsequent investments in tranches up to $50 million at the discretion of the JV partners over a two year investment window. Subject to customary conditions, the parties anticipate that the initial investment will fund in approximately two weeks.
Todd Stevens, President and CEO of CRC, noted, “This joint venture is an excellent opportunity for CRC to accelerate development of CRC’s vast underdeveloped resource base and advance our long term deleveraging efforts. We look forward to partnering with Benefit Street Partners for our mutual benefit.”
Tim Murray, Managing Director of BSP said, “We are proud to partner with CRC and their quality management team. We view CRC’s diverse asset base as an excellent opportunity to structure a joint venture to focus on the primary and secondary development opportunities to enhance CRC’s portfolio.”
About California Resources Corporation
California Resources Corporation is the largest oil and natural gas exploration and production company in California on a gross-operated basis. The Company operates its world class resource base exclusively within the State of California, applying integrated infrastructure to gather, process and market its production. Using advanced technology,


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California Resources Corporation focuses on safely and responsibly supplying affordable energy for California by Californians.

About Benefit Street Partners
BSP is a leading credit-focused alternative asset management firm that, together with affiliates, manages over $18 billion in assets across a broad range of complementary credit strategies including high yield, levered loans, private / opportunistic debt, liquid credit, structured credit and commercial real estate debt. BSP has approximately 150 employees with over 90 investment professionals. BSP is an affiliate of Providence Equity Partners L.L.C., a leading global private equity firm with $50 billion in assets under management across complimentary private equity and credit businesses.

Forward Looking Statement Disclosure
This press release contains 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 include those regarding our expectations as to our future operations, operational results, transactions, projects and reserves. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. Factors (but not necessarily all the factors) that could cause results to differ include:
● commodity price changes
● legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products
● unexpected geologic conditions
● inability to enter efficient hedges

● equipment, service or labor price inflation or unavailability
● availability or timing of, or conditions imposed on, permits and approvals
● lower-than-expected production, reserves or resources from development projects or acquisitions or higher-than-expected decline rates
● disruptions due to accidents, mechanical failures, transportation constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
● factors discussed in “Risk Factors” in our Annual Report on Form 10-K available on our website at crc.com.


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Any forward-looking statement speaks only as of the date on which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.



Contacts:


Scott Espenshade (Investor Relations)
818-661-6010
Scott.Espenshade@crc.com
Margita Thompson (Media)
818-661-6005
Margita.Thompson@crc.com




###