2016 Energy Conference Scotia Howard Weil Todd Stevens| President & CEO| New Orleans, LA| March 23, 2016
Scotia Howard Weil 0316 Forward-Looking / Cautionary Statements 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 specifically include our expectations as to our future financial position, drilling program, production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; sufficiency of our operating cash flow to meet our obligations and fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; our ability to monetize selected assets; restrictions and changes in restrictions imposed by regulations, including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; limitations on our ability to enter efficient hedging transactions; the recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; the effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the spin-off and the agreements related thereto. Material risks are further discussed in “Risk Factors” in our Annual Report on Form 10-K available on our website at crc.com. Words such as "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and CRC 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. This presentation includes financial measures that are not in accordance with United States generally accepted accounting principles (“GAAP”), including PV-10 and Adjusted EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of Adjusted EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix. 2
Scotia Howard Weil 0316 Cautionary Statements Regarding Hydrocarbon Quantities We have provided internally generated estimates for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of December 31, 2014 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 presentation. Factors affecting ultimate recovery include the scope of our ongoing drilling 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. We use the term “oil-in-place”, “net unrisked 3P resources”, “net unrisked prospective resources” and “estimated ultimate recovery” in this presentation to describe estimates of potentially recoverable hydrocarbons remaining in the applicable reservoir. SEC guidelines restrict us from including these measures in filings with the SEC. These have been estimated internally without review by independent engineers and may include shale resources which are not considered in most older, publicly available estimates. Actual recovery of these potential resource volumes is inherently more speculative than recovery of estimated reserves and any such recovery will be dependent upon future design and implementation of a successful development plan. Management’s estimate of original hydrocarbons in place includes historical production plus estimates of proved, probable and possible reserves and a gross resource estimate that has not been reduced by appropriate factors for potential recovery and as a result differs significantly from estimates of hydrocarbons that can potentially be recovered. Ultimate recoveries will be dependent upon numerous factors including those noted above. In addition, we discuss “PUD-like” reserves by which we mean reserves for which our technical evaluation indicates that we would book the reserves as proved undeveloped reserves except that we do not expect to develop them within five years. These are not proved reserves in accordance with SEC regulations. 3
Scotia Howard Weil 03164 2016 Strategic Focus • Priorities and Responses • Deleverage the Balance Sheet for Flexibility • Protect the Base • Defend our Margins • Prepare for Change in Cycle
Scotia Howard Weil 0316 NY00813G / 589203_1.WOR Sacramento Basin 14 MMBoe Proved Reserves 7 MBoe/d production San Joaquin Basin 451 MMBoe Proved Reserves 110 MBoe/d production Ventura Basin 47 MMBoe Proved Reserves 9 MBoe/d production Los Angeles Basin 132 MMBoe Proved Reserves 34 MBoe/d production • World-Class Resource Base In 4 of 12 largest fields in the continental U.S. 644 MMBoe proved reserves • Capital Structure No significant near-term debt maturities Reviewing options to reduce spin-off debt FY 2016 capital investment of $50mm is down >85% from 2015 level • Positioned to Grow as Prices Increase Internally funded capital program designed to live within cash flow and drive growth • Low decline rate that is flattening • Increasing crude oil mix improves margins Operating flexibility to shift basins and drive mechanisms to optimize growth through commodity price cycles CRC at a Glance Reserves as of 12/31/15; Production figures reflect average FY 2015 rates. 5
Scotia Howard Weil 0316 History of Proactive Strategic Decisions 6 Swift, decisive actions have positioned company to weather the commodity downturn. Proactive discussions with lenders and solid asset base provide line of sight to a recovery. 0 5 10 15 20 25 30 0 20 40 60 80 100 120 Ju l-1 4 A u g-1 4 Se p -1 4 O ct -1 4 N o v-1 4 D ec -1 4 Ja n -1 5 Fe b -1 5 Ma r-1 5 A p r-1 5 May-1 5 Ju n -1 5 Ju l-1 5 A u g-1 5 Se p -1 5 O ct -1 5 N o v-1 5 D ec -1 5 Ja n -1 6 Fe b -1 6 Ma r-1 6 A p r-1 6 May-1 6 Ju n -1 6 Ju l-1 6 A u g-1 6 Se p -1 6 O ct -1 6 N o v-1 6 D ec -1 6 C R C D ri lli n g R ig C o u n t B re n t Crude O il Pr ice ($ /B b l) * Oil Price CRC Rig Count Under OXY SPIN-OFF Bank Amendment $2.3 Bn Borrowing Base/ 2016 Capital Budget set at $50mm (down >85% yoy) Debt Exchange Reduced Principal by ~$560 mm Bank Amendment to Relax Covenants/ Suspended Dividend Preliminary 2015 Capital Budget set at $400-450mm (down ~80% yoy) Cut rig count to 6 from 27, began hedging program (covered almost all of 1H15 oil production) With current 2016 hedges we believe we can remain compliant with our revised covenants at ~$28/Bbl Brent index price for year. *As of 3/16/16
Scotia Howard Weil 0316 Living Within Cash Flow -75 125 325 525 725 925 -25 25 75 125 175 225 275 325 1Q15 2Q15* 3Q15 4Q15* FY 2015 FY ($MM ) $ M M Adj. EBITDAX** Operating Cash Flow Capital Investment * Operating cash flow includes payment of a semi-annual cash property tax payment ** See Appendix for reconciliations to GAAP 7
Scotia Howard Weil 0316 Strong Execution Track Record 140 145 150 155 160 165 170 1Q15 2Q15 3Q15 4Q15 M b o e /d Total Production Guidance vs. Actual Production Guidance Range Actual 0 40 80 120 160 1Q15 2Q15 3Q15 4Q15 $ M M Capital Investment Guidance vs. Actual Capital Investment Guidance Range Capex Actual Delivered production toward the high end of guidance with a lower than target capital investment 8
Scotia Howard Weil 0316 Sufficient Liquidity to Manage Near Term Obligations 9 Based on our current capital program and at current price levels, we believe that we will have sufficient liquidity for all of 2016. 2016E Consensus* EBITDA Revolver Availability Annual Cash Interest Expense Annual Cash Interest Expense Term Loan Amortization Term Loan Amortization Capital Budget Minimum Capital Investment $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2/29/2016 2016E 2017E (1) * As of 3/16/16 1 On February 23, 2016 we amended the Credit Facilities and reduced our borrowing base to $2.3 billion. After taking into account borrowing base limitations, we now have the ability to incur total borrowings under the RCF of $1.3 billion less outstanding amounts (~$600MM drawn on 2/29/16), subject to compliance with our quarterly financial covenants which may partially limit our availability.
Scotia Howard Weil 031610 2016 Strategic Focus • Priorities and Response • Deleverage the Balance Sheet for Flexibility • Protect the Base • Defend our Margins • Prepare for Change in Cycle
Scotia Howard Weil 0316 Capitalization as of 12/31/15 ($MM) $25 $625 $433 $829 $2,250 $892 $0 $500 $1,000 $1,500 $2,000 $2,500 Ja n -1 6 Ju l-1 6 Ja n -1 7 Ju l-1 7 Ja n -1 8 Ju l-1 8 Ja n -1 9 Ju l-1 9 Ja n -2 0 Ju l-2 0 Ja n -2 1 Ju l-2 1 Ja n -2 2 Ju l-2 2 Ja n -2 3 Ju l-2 3 Ja n -2 4 Ju l-2 4 Term Loan Debt Maturities ($MM) Focus on Balance Sheet 11 • Deleveraging is a priority • Ratings action initiated transition to secured borrowing base facility • Borrowing base of $2.3 billion effective February 2016 • Approximately $1.6 billion outstanding under senior credit facilities currently* * As of 2/29/16 1 On February 23, 2016 we amended the Credit Facilities and reduced our borrowing base to $2.3 billion. After taking into account borrowing base limitations, we now have the ability to incur total borrowings under the RCF of $1.3 billion less outstanding amounts (currently ~$600MM)*, subject to compliance with our quarterly financial covenants which may partially limit our availability. 2 PV-10 as of 12/31/15 based on SEC five-year rule applied to PUDs using SEC price deck. See Appendix for reconciliation to GAAP. 1st Lien Secured RCF1 739 1st Lien Secured Term Loan 1,000 Senior 2nd Lien Notes 2,250 Senior Unsecured Notes 2,154 Total Debt 6,143 Less cash (12) Total Net Debt 6,131 Equity (916) Total Net Capitalization 5,215 Total Net Debt / Net Capitalization 118% Total Net Debt / LTM Adjusted EBITDAX 6.8x LTM Adjusted EBITDAX / Interest Expense 2.8x PV-102 / Total Net Debt 0.8x Total Net Debt / Proved Reserves ($/Boe) $9.52 Total Net Debt / PD Reserves ($/Boe) $12.75 Total Net Debt / Production ($/Boepd) $38,319
Scotia Howard Weil 0316 $94 $55 $64 $48 $37 $33 0 10 20 30 40 50 60 70 80 90 100 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 10/1/14 3/31/15 6/30/15 9/30/15 12/31/15 2/29/16 B re n t Oil ($ /B b l) Total D eb t ($ M ) Total Debt Long Term Notes Term Loan Revolving Credit Facility Oil Price Deleveraging Update 12 Given the significant decline in oil prices, focused on 1) free cash flow to reduce residual working capital from Spin, and 2) successful execution of debt exchange
Scotia Howard Weil 031613 • We have accessed various deleveraging alternatives and are taking decisive steps to delever the balance sheet Deleveraging Options UPSTREAM • JV • M&A MIDSTREAM • MLP • Drop into Existing MLP • Sale • Triple Net Lease CAPITAL MARKETS • Debt Exchange AVAILABLE ASSETS • 14 Gas Plants with 650 MMcfd Capacity • Elk Hills has largest Gas Plant Complex in CA • 300 Compressors / Stations with 395,000 HP of Compression • 600 MW Electrical Generation with 700 miles of High Voltage Transmission Lines • 305 Tank Settings / LACT / Sales Facilities • 74 Water Plants / Treatment Facilities • 50 Steam Generators with 220,000 Bbl Steam Capacity • ~20,000 Miles of Pipelines AVAILABLE ASSETS • 2.4 Million Acres • ~60% of Land held in Fee • Large Economic Development Project Inventory • Seismic • Robust Exploration Portfolio TRANSACTION • Exchange offer for Unsecured Notes reduced debt by $563 million
Scotia Howard Weil 031614 2016 Strategic Focus • Priorities and Response • Deleverage the Balance Sheet for Flexibility • Protect the Base • Defend our Margins • Prepare for Change in Cycle
Scotia Howard Weil 0316 744 768 768 644 0 100 200 300 400 500 600 700 800 900 1000 FY 2013 Improved Recovery Extensions and Discoveries Purchases Performance Revisions Production FY 2014 Performance Related Revisions Extensions and Discoveries Improved Recovery Purchases Price Revisions Production FY 2015 P ro ve d R e se rv e s (MMB o e ) Consistent Replacement of Reserves from Resource Base 15 FY 2013 FY 2014 FY 2015 Reserve Replacement(1) 159%* 171%* 140%* F&D ($/Boe)(1) $19.00* $21.20* $4.88* Total Gross Identified Locations 17,691 19,800 23,450 Additional Potential Locations 6,400 6,400 6,400 (1) See End Notes for more detail. *Excluding price adjustments.
Scotia Howard Weil 0316 Resource Base Enables Resilient Production Profile Rich asset portfolio and thoughtful capital allocation deliver high margin production and operational flexibility through the price cycle • Conventional assets have relatively low decline rates, long production life • Large inventory of conventional development projects that are expected to be repeatable, with low technical risk Application of modern technologies produces growth opportunity in California • Deferring many high-return project opportunities until prices rise • Identifying investments economically viable through commodity price cycles 16 M b o e/ d Production By Stream (MBoe/d) Oil NGL Gas Guidance 159 Mboe/d Average Oil Production 160 Mboe/d 99 MBbl/d 104 MBbl/d
Scotia Howard Weil 031617 2016 Strategic Focus • Priorities and Response • Deleverage the Balance Sheet for Flexibility • Protect the Base • Defend our Margins • Prepare for Change in Cycle
Scotia Howard Weil 0316 Opportunistically Built Hedge Portfolio* * As of March 17, 2016• Hedge book started at zero post spin; we target hedges on 50% of production • Strategy focuses on protecting cash flow for capital investments and covenant compliance • Q1 2016 averages include Brent-based puts for 10,000 barrels of oil per day of our March 2016 production at $46 per barrel Q1 2016 Q2 2016 Q3 2016 Q4 2016 2017 2018 Calls Barrels per Day 35,500 35,500 3,000 3,000 30,000 23,300 Wtd Avg Ceiling Price per Barrel $66.15 $66.15 $74.42 $74.42 $55.68 $57.99 Puts Barrels per Day 33,800 55,500 28,000 3,000 - - Wtd Avg Floor Price per Barrel $51.75 $50.14 $50.65 $50.00 - - Swap Barrels per Day - - 1,000 6,000 - - Wtd Avg Price per Barrel - - $61.25 $46.27 - - 18
Scotia Howard Weil 0316 Defending Margins Through Efficiencies and Focus on Cash Costs $4.97 $5.00 $5.28 $5.57 $5.09 $5.13 $4.61 $4.80 $3.74 $3.88 $3.79 $3.55 $3.65 $3.63 $2.89 $2.10 $19.00 $19.03 $18.35 $16.65 $16.20 $16.59 $16.91 $15.51 $2.23 $1.06 $1.69 $4.49 $1.11 $0.52 $0.34 $0.49 $0 $5 $10 $15 $20 $25 $30 $35 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16E Cash Costs $/Boe Adj G&A* Taxes (non income) Production Costs Exploration Guidance 2014 Average = $29.57 2015 Average = $24.91 * Adjusted G&A expenses exclude early retirement and severance costs which amounted to $10 million in 2Q15, $62 million in 3Q15 and $(5) million in 4Q15. 19 4Q15 production costs per boe were approximately 7% lower year over year. Lower fourth quarter costs reflected cost reductions across the board, particularly in well servicing efficiency, surface operations and energy use, and were also aided by lower natural gas and power prices.
Scotia Howard Weil 031620 2016 Strategic Focus • Priorities and Response • Deleverage the Balance Sheet for Flexibility • Protect the Base • Defend our Margins • Prepare for Change in Cycle
Scotia Howard Weil 0316 Progressing Inventory to VCI Threshold 21 0 1,000 2,000 3,000 4,000 5,000 6,000 $40 $50 $60 Dri llin g an d W o rk o ve r In ve n to ry ( $MM ) Brent Marker Price ($/Bbl) Economic Project Inventory VCI 1.3 VCI 1.0
Scotia Howard Weil 0316 2015 Net Proved Reserves (MMBoe) 644 2015 % Oil– Net Proved1 72% Pre-Tax Proved PV-10 ($ billion)2 5.06 2015 Avg. Net Production (MBoe/d) 160 2015 % Oil Production 65% 2015 Net Acreage (million acres) 1 2.4 2015 Identified Gross Locations1 23,450 1 As of 12/31/15. Drilling locations exclude 6,400 gross prospective locations. 2 See Appendix for reconciliation to GAAP. Figures shown are full year 2015, unless otherwise noted. San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin 2015 Net Proved Reserves (MMBoe) 451 132 47 14 2015 % Proved Developed 72% 80% 77% 100% 2015 % Liquids – Net Proved 1 78% 98% 89% 0% 2015 Avg. Net Production (MBoe/d) 110 34 9 7 2015 % Oil Production 58% 100% 67% 0% 2015 Net Acreage (million acres) 1 1.6 <0.1 0.3 0.5 2015 Identified Gross Drilling Locations 1 19,150 1,650 1,500 1,150 Diverse Assets with Flexible Development Opportunities • Diversity of basins, drive mechanisms • Predictable production, low decline rates • Multiple stacked reservoirs • Development targets include repeatable projects with low technical risk 22
Scotia Howard Weil 0316 Recovery Factors for Discovered Fields¹ 9 40 0 5 10 15 20 25 30 35 40 45 Cum Recovered to Date Remaining 3P + Contingent RF + 10% RF + 15% RF + 20% Original in Place Billion Boe 1 Does not include undiscovered unconventional resource potential. • In place volumes of ~40 Bn Boe at low recovery factor (22%) to date • Conventional “value chain” approach to life of field development • Unconventional success with attractive upside positioning • Untapped opportunities to apply technology advances to California • Good return projects that can withstand a variety of price environments Large in Place Volumes with Significant Upside for CRC 23
Scotia Howard Weil 0316 Proven Track Record in Sensitive Environments • Operator of choice in coastal environments • Proven coexistence with sensitive environments • 2.6 billion gallons of reclaimed water supplied to agriculture in 2015 • Committed to excellence in safety and mechanical integrity 24
Scotia Howard Weil 0316 • World-class asset base with diverse and rich resources. • Capacity for significant production growth at higher prices as we develop low-decline, lower-risk opportunities. • Committed to capital budgets that live within our cash flows. • As we bring our capital structure in line with today’s prices, we’re pursuing a number of options to de-leverage. • Legacy of safe production and commitment to regulatory and community outreach in California. Well Positioned for Growth in Recovery 25
Scotia Howard Weil 0316 California Resources Corporation Appendix 26
Scotia Howard Weil 0316 End Notes: 27 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 48%, 82% and 81% of the additions for 2015, 2014 and 2013, respectively, are proved undeveloped. There is no guarantee that historical sources of reserves additions will continue as many factors fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, affect reserves additions. Management uses this measure to gauge results of its capital allocation. The measure is limited in that reserves may be added and produced based on costs incurred in separate periods and other oil and gas producers may use different replacement ratios affecting comparability. Finding and Development costs for the capital program are calculated by dividing the costs incurred from the capital program (development, exploration and asset retirement costs (except as noted)) by the amount of proved reserves added in the same year from improved recovery and extensions and discoveries (excluding acquisitions and revisions). Our management believes that reporting our finding and development costs can aid evaluation of our ability to add proved reserves at a reasonable cost and is not a substitute for our 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. Our calculations of finding and development costs may not be comparable to similar measures provided by other companies. (2) Fi di g d Development Costs 2015 2014 2013 O g ic Co t incurred - in millions (A) $ 333 (D) $ 2,086 $ 1,705 Organic Costs incurred (excluding ARO adjustments) - in millions (B) $ 395 (E) $ 2,099 $ 1,691 Proved Reserves Added - MMBOE (C) 81 99 89 Organic Finding and Development Costs - $/BOE (A)/(C) $ 4.11 $ 21.07 $ 19.15 Organic Finding and Develop ent Costs (excluding ARO adjustments) - $/BOE (B)/(C) $ 4.88 $ 21.70 $ 19.00 (D) Includes development and exploration costs, as well as ARO; excludes acquisitions. (E) Reflects the items in (D) above, except that it excludes the ARO adjustment, which reduced costs incurred in 2015 and 2014. (1) Organ ic Reserves Replacement Rat io 2015 2014 2013 Proved reserves added in 2015 – MMBOE Extensions and Discovery 33 1 0 Improved Recovery 3 117 89 Revisions related to performance 45 (19) 0 Total (A) 81 99 89 Production in 2015 – MMBOE (B) 58 58 56 Organic Reserves Replacement Ratio (A)/(B) 140% 171% 159%
Scotia Howard Weil 0316 End Notes: 28 (3) Our total production costs consist of variable costs that tend to vary depending on production levels, and fixed costs that do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term as they can be managed based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term, however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. While a certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. Overall, we believe less than one-third of our operating costs are fixed over the life cycle of our fields. We actively manage our fields to optimize production and costs. If we see growth in a field we increase capacities, and similarly if a field is reaching the end of its economic life we would manage the costs while it remains economically viable to produce.
Scotia Howard Weil 0316 Non-GAAP Reconciliation for Adjusted EBITDAX For the Fourth Quarter Ended December 31, For the Twelve Months Ended December 31, ($ in millions) 2015 2014 2015 2014 Net Income/(loss) ($3,282) ($2,091) ($3,554) ($1,434) Interest expense 82 72 326 72 Income taxes expense/(benefit) (1,757) (1,431) (1,922) (987) Depreciation, depletion and amortization 247 312 1,004 1,198 Exploration expense 7 68 36 139 Asset Impairments 4,852 3,402 4,852 3,402 Other (a) 77 122 164 158 Adjusted EBITDAX $226 $454 $906 $2,548 Net cash provided by operating activities ($9) $504 $403 $2,371 Interest expense 82 72 326 72 Cash income taxes - (17) - 165 Cash exploration expenses 7 19 27 38 Changes in operating assets and liabilities 104 (155) 147 (143) Other, net 42 31 3 45 Adjusted EBITDAX $226 $454 $906 $2,548 (a) Includes non-cash and unusual or infrequent charges. 29
Scotia Howard Weil 0316 Revised Amendment Previous Maximum Leverage First Lien Leverage Ratio suspended through 12/31/16; At and after 3/31/17 : < 2.25x Maximum First Lien Secured Leverage Ratio: 2.25x Minimum Interest Coverage 03/31/16 : > 2.00x 06/30/16 : > 1.50x 09/30/16 : > 1.25x 12/31/16 : > 0.70x Thereafter: > 2.00x 2.00x Cumulative Minimum EBITDAX 03/31/16 : $55mm 06/30/16 : $130mm 09/30/16 : $190mm 12/31/16 : $250mm N/A Borrowing Base, Revolver Commitment, Total Commitment $2.3 Bn Borrowing Base $1.6 Bn Revolver Commitment $2.6 Bn Total Commitment $3.0 Bn Borrowing Base $2.0 Bn Revolver Commitment $3.0 Bn Total Commitment Redetermination Semi-Annually, May 1st and November 1st Annually –May 1st Anti-hoarding Provisions Cash > $150mm must be used to the repay the revolver Cash > $250mm must be used to the repay the revolver Other • Maximum Capital Expenditures: $100mm • General lien basket of up to $50mm • Accordion and Swingline eliminated • Increase of 75 bps across pricing grid General lien basket of greater of $200mm and 1.5% of Consolidated Total Assets Amendment – Summary of General Terms & Conditions 30
Scotia Howard Weil 0316 Revised Amendment Previous Sale of Borrowing Base Properties 100% of proceeds used to repay first the term loan, then the revolver Subject to potential repayment of revolver due to resultant borrowing base reduction Sale of Non-Borrowing Base Properties • 100% of proceeds used to repay first the term loan, then the revolver except: • 40% of proceeds can be used to repurchase: • 2L notes at a minimum of 40% discount • Unsecured notes at a minimum of 60% discount $150 million + 50% of proceeds could be used to repurchase senior notes and other junior debt Deleveraging Debt Basket A • May incur debt of $1Bn secured with junior liens • 40% of proceeds can be used to repurchase: • 2L notes at a minimum of 40% discount • Unsecured notes at a minimum of 60% discount N/A Deleveraging Debt Basket B • May incur debt of up to $200mm secured with liens on non- borrowing base properties in order to repurchase: • 2L notes at a minimum of 40% discount • Unsecured notes at a minimum of 60% discount N/A Junior Notes Basket Used in the December 2015 bond exchange Up to $2.25 Bn in junior notes Amendment – Summary of Liability Management Terms 31
Scotia Howard Weil 0316 CRC Leading California Producer California Pure-Play Top California Producers in 2015* • An independent E&P company spun off by Occidental Focused on high-return assets in California • Largest private mineral acreage-holder, with 2.4 million net acres1 ~60% of total net mineral interests position held in fee1 • Conventional and unconventional opportunities Primary production Waterfloods & gas injection Steam / EOR • Substantial base of Proved Reserves1 644 MMBoe (75% PD, 72% oil, 81% liquids) PV-10 of $5.1 billion (SEC 5 year rule applied to PUDs) 1 As of 12/31/2015 *Gross operated production from DOGGR data for 2015 full year average 32 0 50 100 150 200 250 300 G ro ss O p era te d MB o ep d Growth of Top California Producers 196 161 134 35 34 - 20 40 60 80 100 120 140 160 180 200 CRC Chevron USA Aera Energy Freeport McMoRan LINN Energy G ro ss O p era te d MB o ep d Aera Chevron CRC
Scotia Howard Weil 031633 Best in Class Corporate Decline Rate Unlabeled operators include : AMXG, AREX, BBG, BCEI, CLR, CPE, CRK, CWEI, CXO, EGN, EOG, EPE, EXXI, FANG, GDP, HK, JONE, LPI, MPO, NFX, OAS, PDCE, PE, PVA, PXD, ROSE, RSPP, SFY, SM, SN, TPLM, WTI, XEC Source: ITG IR, raw data provided by Drilling Info, Inc.
Scotia Howard Weil 0316 San Joaquin $85 65% Los Angeles $45 35% Drilling $130 32% Dev. Facilities $120 30% Workovers $55 14% Exploration $15 4% Other1 $81 20% Commentary 2015 Drilling Capital Actuals – By Basin 2015 Total Capital Actuals 2015 Drilling Capital Actuals – By Drive • 2015 actual capital investment of $401 million was directed almost entirely toward oil-weighted investments • Total and oil production increased 1% and 5% respectively in 2015 without exceeding cash flows • Expect multi-year crude oil maintenance capital range of $600-$700 million per year to maintain flat crude oil production* • Primary tenet for 2016 capital program of $50mm is to invest within cash flow, emphasizing mechanical integrity and safe operations Total: $401 million Total: $130 million Primary $10 8% Steamfloods $70 54% Waterfloods $50 38% Self-Funded Capital Investment Program 1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments. *Calculated over 3 years based on current operating costs and expenses in the current commodity environment. 34
Scotia Howard Weil 0316 $95.12 $94.21 $97.97 $93.00 $48.80 $103.80 $104.02 $104.16 $92.30 $49.19 $110.90 $111.70 $108.76 $99.51 $53.64 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 2011 2012 2013 2014 2015 $ /B b l WTI Realizations Brent $4.11 $2.81 $3.66 $4.34 $2.75 $4.31 $2.94 $3.73 $4.39 $2.66 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 2011 2012 2013 2014 2015 $ /M cf NYMEX Realizations NGL Price Realization - % of WTI Realization % of WTI 109% 110% 106 % 99% 97% Realization % of NYMEX 105% 105 % 102 % 101% 97% Oil Price Realization* Gas Price Realization* 74% 56% 51% 51% 40% 0% 10% 20% 30% 40% 50% 60% 70% 80% 2011 2012 2013 2014 2015 % o f WT I CRC – Price Realizations * Reflects realizations with hedges 35 • Since California imports a significant percentage of its crude oil requirements, California refiners typically purchase crude oil at international index- based prices for comparable grades • California also imports approximately 90% of its natural gas • Discrete California market issues in the past have impacted differentials
Scotia Howard Weil 0316 San Joaquin Basin • Oil and gas discovered in the late 1800s • Accounts for ~69% of CRC production • ~25 billion barrels OOIP in CRC fields1 • Cretaceous to Pleistocene sedimentary section (>25,000 feet) • Source rocks are organic rich shales from Moreno, Kreyenhagen, Tumey, and Monterey Formations • Thermal techniques applied since 1960s • 2015 average net production of 110 MBoe/d (58% oil) • Elk Hills is the flagship asset (~55% of CRC San Joaquin production) • Two core steamfloods - Kern Front and Lost Hills • Early stage waterfloods at Buena Vista and Mount Poso Overview Key Assets Basin Map -Legend- Oxy Land Oil Fields Gas Fields Buena Vista Pleito Ranch Elk Hills Kettleman Lost Hills Mt Poso CRC Land Kern Front 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates. 36
Scotia Howard Weil 0316 0 20 40 60 80 100 120 140 1998 2000 2002 2004 2006 2008 2010 2012 2014 N et MB o e/ d • CRC’s flagship asset, a 100 year-old field with exploration opportunities • Large fee property with multiple stacked reservoirs • Light oil from conventional and unconventional production • Largest gas and NGL producing field in CA, one of the largest fields in the continental U.S.1, >3,000 producing wells • 7.8 billion barrels OOIP2 and cumulative production of over 1.6 billion Boe • 2015 avg. net production of 60 MBoe/d (38% of total production) • Less than a third of our operating costs are fixed.3 • 540 MMcf/d processing capacity • 2 CO2 removal plants • Over 4,200 miles of gathering lines • 3 gas plants (including California’s largest) • 45 MW cogeneration plant • 550 MW power plant Overview Comprehensive Infrastructure Field Map Production History 1 DOGGR data and U.S. Energy Information Administration. Elk Hills Buena Vista RR Gap Elk Hills Area - Overview 2 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates. 37 3 See End Notes for more information.
Scotia Howard Weil 031638 • Multiple mechanisms within Elk Hills Field Primary Waterflood Unconventional • Longer term base production decline ~15% • Transition to steam flood & EOR projects would further flatten declines Building Life of Field Plans – Elk Hills Field 0 20,000 40,000 60,000 80,000 100,000 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 N e t B O EP D ELK HILLS FIELD DEVELOPMENT In-Field Development Exploration Discoveries Base Decline ~15% Life of field plans help optimize returns by identifying the total resource and facilitating maximization of production through our value recovery chain.
Scotia Howard Weil 0316 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 2012 2014 2015 Elk Hills Field Opex per Well 39 Effective Management of Elk Hills Field Operating Costs* *Transition from primary to secondary production in Elk Hills has been occurring during this period. The Wilmington Field has similarly experienced declines in Opex per well and Opex per Boe despite a significantly higher WOR (~39 in 2014). 10.0 11.0 12.0 13.0 14.0 15.0 16.0 2012 2014 2015 Elk Hills Field Water-Oil Ratio (WOR) 2,000 2,500 3,000 3,500 4,000 4,500 5,000 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 2012 2014 2015 W el l C o u n ts O p era ti n g C o st, $ /B o e Elk Hills Field Opex, $/Boe Elk Hills Field - Opex, $/Boe Well Counts
Scotia Howard Weil 0316 0 2000 4000 6000 8000 10000 12000 14000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 N et B OP D Steamflood Example Kern Front 40 • Single digit base declines • Multi-year Investments of drilling and facilities spending • 2008-2015 Investment $605 million • Added reserves at $10.45/bbl* • Would likely plateau for a period of time if drilling stopped • >850 remaining PUD locations Capital Efficient Growth Delivers Long Term Returns Modest capital investment in new wells for both steam floods and water floods, and the associated facilities and capital workovers yield solid long-term base returns for CRC. Base Decline 9% 2001-2007 Program (30 wells/year) 2008-2015 Program (95 wells/year) Source: CRC * See End Notes for more information.
Scotia Howard Weil 0316 Los Angeles Basin • Large, world class basin with thick deposits • Kitchen is the entire basin, hydrocarbons did not migrate laterally; basin depth (>30,000 ft) • ~10 billion barrels OOIP in CRC fields1 • Most significant discoveries date to the 1920s – past exploration focused on seeps & surface expressions • Very few deep wells (> 10,000 ft) ever drilled • Focus on urban, mature waterfloods, with generally low technical risk and proven repeatable technology across huge OOIP fields • 2015 average net production of 34 MBoe/d (100% oil) • Over 20,000 net acres • Major properties are world class coastal developments of Wilmington and Huntington Beach Overview Key Assets Basin Map 41 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates.
Scotia Howard Weil 0316 - 50 100 150 200 250 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 M M B o e Net Proved Reserves Production to Date Overview Field Map Proved Reserves & Cumulative Production Structure Map & Acquisition History * • CRC’s flagship coastal asset: acquired in 2000 • Field discovered in 1932; 3rd largest field in the U.S. • Over 7 billion barrels OOIP (34% recovered to date)1 • Depths 2,000’ – 10,000’ (TVDSS) • 2015 avg. production of 35 MBoe/d (gross) • Over 8,000 wells drilled to date • Less than a third of our operating costs are fixed2 • PSC (Working Interest and NRI vary by contract) • CRC partnering with State and City of Long Beach *Proved reserves prior to 2009 represent previously effective SEC methodology. Proved reserves for 2009 – 2015 are based on current SEC reserve methodology and SEC pricing. 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates. Tidelands Acquired: 2006 Belmont Offshore Acquired: 2003 Long Beach Unit Acquired: 2000 Pico Properties Acquired: 2008 Wilmington Field - Overview 42 2 See End Notes for more information.
Scotia Howard Weil 031643 • Example of Wilmington (“mature waterflood”) • Growing Proven Reserves 120% Reserves Replacement since 2011* • Increased inventory of well locations Drilled 530 wells Additional 677 wells identified in mature field • Replaced 128% of wells drilled Big Fields Continue To Get Bigger…. Replenishing Inventory - # Drilling Locations Inventory of locations** in 2011 712 Wells drilled 2011-15 -530 Additional inventory 2011-15 677 Remaining locations 859 Large, long-life assets provide multiple opportunities to enhance production and expand inventories. * See End Notes for more information. ** Locations – include PUDs, PUD-like locations (outside 5 year SEC rule) and other unproven locations. ***Proved reserves determined at EOY SEC Reserve prices for each year. 0 20 40 60 80 100 120 2011 Entry Production Proven Adds 2015 Exit P ro ve n R es er ve s (M m bo e) Mature Waterflood Wilmington Proved Reserves***
Scotia Howard Weil 0316 Ventura Basin • Estimated ~3.5 billion barrels OOIP in CRC fields1 • Operate 29 fields (about 40% of basin) • ~300,000 net acres • Multiple source rocks: Miocene (Monterey and Rincon Formations), Eocene (Anita and Cozy Dell Formations) • 2015 average net production of 9 MBoe/d (67% oil) • In 2013, shot 10 mi2 of 3D Seismic > First 3D seismic acquired by any company in the basin Overview Key Assets Basin Map • CRC has four early stage waterfloods • Ventura Avenue Field analog has >30% RF • CRC fields have 3.5 Bn Boe in place at 14% RF Waterflood Potential2 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates 2 Source: USGS 44
Scotia Howard Weil 0316 Sacramento Basin • Exploration started in 1918 and focused on seeps and topographic highs. In the 1970s the use of multifold 2D seismic led to largest discoveries • Cretaceous Starkey, Winters, Forbes, Kione, and the Eocene Domengine sands • Most current production is less than 10,000 feet • 3D seismic surveys in mid 1990s helped define trapping mechanisms and reservoir geometries • CRC has 53 active fields (consolidated into 35 operating areas where we have facilities) • 2015 average net production of 7 MBoe/d (100% dry gas) • Produce 85% of basin gas with synergies of scale • Price and volume opportunity Overview Key Assets Basin Map 45
Scotia Howard Weil 0316 • Conventional fields in various stages of development • Base assets in place – advancing recovery with traditional means • Moving recoveries from primary through EOR • Primary (94 fields) • Production with natural energy of reservoir or gravity drainage • Waterflood (17 fields) • Incremental recovery beyond primary with pressure support and displacement • Steam / EOR (13 fields) • Enhanced recovery from reservoirs using techniques such as steam or CO2 0 10 20 30 40 50 60 70 80 Primary Waterflood Steam R e co ve ry o f O ri g. in P la ce ; R F% Approximate current average CRC RF% Development program is based on reservoir characteristics, reserves potential and expected returns Typical Recoveries by Mechanism Type Creating a Recovery Value Chain 46
Scotia Howard Weil 0316 A NET WATER SUPPLIER • CRC’s delivery of reclaimed produced water to agriculture in 2015 exceeded the amount of fresh water we purchased by nearly 1 billion gallons • We expedited the North Kern Drought Relief project in 2015, achieving a 30% increase in our water supply to agriculture • We recycled approximately 77% of our produced water in improved or enhanced recovery operations in 2015 • We reduced our purchased fresh water volume by over 11% in 2015 94% 3% 3% WATER MANAGED IN CRC’s OPERATIONS Produced Water Fresh Water Non-Fresh Water In 2015, CRC’s steamflood operations supplied more than 2.6 billion gallons – over 8,100 acre-feet – of water for irrigation This preserves fresh water for other beneficial uses, equivalent to the needs of approximately 17,800 families per year 47 CRC’s operations in Long Beach use recycled water for 99.5% of their total water use
Scotia Howard Weil 0316 Non-GAAP Reconciliation for PV-10 ($ in millions) At December 31, 2015 PV-10 of Proved Reserves $5,059 Present value of future income taxes discounted at 10% (1,035) Standardized Measure of Discounted Future Net Cash Flows $4,024 PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil an 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. 48