Third Quarter 2015 Earnings Review Todd Stevens President & CEO Mark Smith Sr. EVP & CFO Los Angeles, CA November 5, 2015
Forward-Looking / Cautionary 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 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 included in this presentation. 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 effect of our debt on our financial flexibility; sufficiency of our operating cash flow to fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; our ability to monetize selected assets; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; 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, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business. 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 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. Some of the data in this presentation is from external sources as noted. While we believe it is accurate, we have not independently verified the data and do not represent or warrant that it is accurate, complete or reliable. 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
World Class Resource Base Interests in 4 of the 12 largest fields in the lower 48 states 768 MMBoe proved reserves (12/31/2014) Largest producer in California on a gross operated basis with significant exploration and development potential Shareholder Value Focus Internally funded capital expenditure program Optimized capital allocation Unlocking under-exploited resource potential utilizing modern technology Portfolio of Lower-Risk, High- Growth Opportunities Oil weighted reserves Broad exploration and development program 30%-100%+ rates of return on select individual projects California Heritage Strong track record of operations since 1950s Longstanding community and state relationships Actively involved in communities with CRC operations Management Expertise Successful operations exclusively in California Assembled largest privately-held land position in California Operator of choice in sensitive environments
Management Priorities and Response Priorities 1. Address Balance Sheet 2. Adjust Activity Levels for Current Environment Live within means and bring capital investments in line with projected cash flow 3. Focusing on base production and protecting our margins 4. Right-size costs for the current operating environment Execution Narrowed discussions with leading counterparties on preferred transactions and in detailed discussions. Paid down $109 million of debt. Balanced 15YTD cash flows of $412 million with capital investment of $323 million. Achieved 15YTD production target with less than expected capital investment Delivered average 3Q15 oil production of 103,000 bbls/day, up 3% yoy period and higher than the FY 2014 average of 99,000 bbls/day Focused on costs. Total cash costs on a per boe basis excluding interest expense declined ~4% in 3Q15 vs 3Q14 Op Cash costs down to $16.91/boe for 3Q15, compared to $18.35/Boe in 3Q14 G&A reduction 4
$ MM Operating Cash Flow CRC Executing on Controllables 700 600 500 400 300 631 200 100 0 3Q14 Volume Price Costs Interest Tax Working Capital and Other 180 3Q15 5
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. 6
Capital Allocation Approach Portfolio Management since spin-off Three principal drivers: o Maximize long-term value VCI > 1.3 o Oil production growth o Financial discipline self-funding business Results in combination of projects that provide quick payback (workovers), longer term value / future growth (steamfloods/waterfloods) and high IP s (conventional/tight sands/unconventional). Value Creation Index VCI = PV10 pre-tax cash flows PV10 of investments Measures value created per dollar investment ( Bang for the buck ) 7
Drilling Capital ($Bn) Flexible High Return Inventory Capital associated with currently identified projects delivering VCI >1.3* Current average well cost ~$1.1 MM Multi-year inventory allows maintenance of flat production at different points in the price curve $7.0 $6.0 Actionable Inventory at Various Price Levels $5.0 $4.0 $3.0 $2.0 Workover Waterflood Unconventional Steamflood Primary $1.0 $0.0 Pace Rigs/Year 55 Strip** 65 75 Years of Inventory 3 11.1 21.4 24.0 37.1 5 6.7 12.8 14.4 22.2 7 4.8 9.2 10.3 15.9 10 3.3 6.4 7.2 11.1 *Does not include injectors **Strip as of 11/3/15 8
Progressing Inventory to VCI Threshold GREATER ELK HILLS AREA INVENTORY OF POTENTIAL PROJECTS 2016-2020 VCI >= 1.0 VCI >= 1.3 Plan Year 2016 to 2020 Plan Year 2016 to 2020 @ $50 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $50 Oil, $3.00 Gas ($3.50 Gas for >= 2017) Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Conventional 176 0 38 103 Conventional 0 0 38 11 Unconventional 171 0 129 457 Unconventional 10 0 125 82 Waterflood 65 29 152 154 Waterflood 41 23 146 126 Grand Total 412 29 319 714 Grand Total 51 23 309 219 @ $60 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $60 Oil, $3.00 Gas ($3.50 Gas for >= 2017) Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Conventional 176 0 38 103 Conventional 164 0 38 100 Unconventional 198 0 129 514 Unconventional 25 0 129 116 Waterflood 209 32 155 252 Waterflood 65 29 152 154 Grand Total 583 32 322 869 Grand Total 254 29 319 370 @ $70 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $70 Oil, $3.00 Gas ($3.50 Gas for >= 2017) Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Conventional 443 0 39 386 Conventional 164 0 38 100 Unconventional 223 0 129 573 Unconventional 89 0 129 273 Waterflood 209 40 185 264 Waterflood 66 29 155 157 Grand Total 875 40 353 1,223 Grand Total 319 29 322 530 9
Targeting Higher-Margin, Higher Return, Low Decline Crude Oil Projects 2015 Capital Budget ($MM) By Drive Unconventional $35 8% Other $20 5% Primary $40 9% Total: $440 million Exploration $15 3% Focus on steamflood and waterflood projects, which provide: Attractive returns at current prices Steamfloods $155 35% 2015 Total Capital Budget Exploration $15 3% Other $95 22% Development Facilities $130 30% 1 Waterfloods $175 40% Drilling $150 34% Workover $50 11% Lower base decline and risk profile Oilier, higher margin production mix Expect slightly higher crude oil production in 2015 vs. 2014; and relatively flat overall production on a BOE basis 1 Other includes seismic, maintenance and other investments. 10
Deleveraging Options We have assessed various deleveraging alternatives and are taking decisive steps to delever the balance sheet UPSTREAM JV M&A AVAILABLE ASSETS 2.3 Million Acres ~60% of Land held in Fee Large Economic Development Project Inventory Seismic Robust Exploration Portfolio MIDSTREAM MLP Drop into Existing MLP Sale Triple Net Lease 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 CAPITAL MARKETS 11
$ MM Living Within Cash Flow 300 250 200 150 100 50 0 1Q15 2Q15 3Q15 Adj. EBITDAX* Operating Cash Flow Capital Investment * See Appendix for reconciliations to GAAP 12
Defending Margins Through Efficiencies and Focus on Cash Costs Cash Costs $/Boe $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 2014 Average = $29.57 $2.23 $1.06 $1.69 $4.49 2015E Average = $25.51 $1.11 $0.52 $0.34 $19.00 $19.03 $18.35 $16.65 $16.20 $16.59 $16.91 $3.74 $3.88 $3.79 $3.55 $3.65 $3.63 $2.89 $4.97 $5.00 $5.28 $5.57 $5.09 $5.13 $4.61 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15E Adj G&A* Taxes (non income) Production Costs Exploration Guidance 3Q15 production costs were approximately 8% lower year over year. Lower third 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. * Adjusted G&A expenses exclude early retirement and severance costs which amounted to $10 million in 2Q15 and $62 million in 3Q15. 13
Focus on Oil Enhances Base & Margins Production By Stream (MBoe/d) Average Total Production 159 Mboe/d Average Oil Production 99 MBbl/d 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15E FY 2014 FY 2015E Oil NGL Gas Guidance 14
3Q15 Results Summary Comparison 3Q14 2Q15 3Q15 Adjusted EPS* $0.48 ($0.13) ($0.22) Oil Production 100 MBbl/d 104 MBbl/d 103 MBbl/d Total Production 160 MBoe/d 161 MBoe/d 158 MBoe/d Realized Oil Price w/hedge ($/Bbl) $96.27 $56.73 $47.79 Realized NGL Price ($/Bbl) $47.20 $20.47 $16.92 Realized Natural Gas Price ($/Mcf) $4.24 $2.49 $2.83 Adjusted EBITDAX* $662 mm $270 mm $212 mm Capital Investments $566 mm $95 mm $95 mm Cash Flow from Operations $631 mm $117 mm $180 mm * See Appendix for reconciliations to GAAP 15
% of WTI $/Bbl $/Mcf CRC Price Realizations Oil Price Realization* Gas Price Realization $120 $110 $100 $90 $80 $70 $60 $50 $40 $30 WTI Realizations Brent $110.90 $111.70 $108.76 $99.51 $103.80 $104.02 $93.00 $95.12 $94.21 $97.97 $104.16 $92.30 $56.61 $51.00 $50.28 2011 2012 2013 2014 YTD 3Q15 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 NYMEX Realizations $4.31 $4.39 $3.73 $4.11 $4.34 $2.94 $3.66 $2.86 $2.81 $2.72 2011 2012 2013 2014 YTD 3Q15 Realization % of WTI 109% 110% 106 % 99% 97% Realization % of NYMEX 105% 105 % 102 % 101% 92% NGL Price Realization - % of WTI 80% 74% 70% 56% 60% 51% 51% 50% 39% 40% 30% 20% 10% 0% 2011 2012 2013 2014 YTD 3Q15 Several discrete events in California in 1H contributed to widening differentials Realizations have gradually improved since Q1 * Reflects realizations with hedges 16
Strong Oil Volumes Drive Quarterly Production Boe/d 165,000 160,000 +3,000-4,000-1,000 155,000 150,000 160,000 158,000 145,000 140,000 3Q14 Oil Gas NGL 3Q15 17
Cost Variance 3Q14 2Q15 3Q15 Production costs ($/Boe) Taxes other than on income ($MM) Exploration expense ($MM) Interest expense ($MM) $18.35 $16.59 $16.91 $56 $53 $42 $25 $7 $5 NA $83 $82 18
Capex Reduction 2014 Actual 2015 Actual Q4 Expected Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec Rigs 28 25 6 4 3 3 3 3 3 3 3 3 3 3 3 Quarterly Operations CAPEX, $mm $520 $133 $95 $95 $90-100* Focus on investing within expected cash flows despite availability of additional investment opportunities that are economic at current strip prices * Fourth Quarter 2015 Guidance 19
Opportunistically Built Hedge Portfolio $80 $75 40,000 Bbl/d $73.88 call 2015/2016 Crude Oil Brent Hedges * 3,000 Bbl/d $74.42 call $70 $65 40,000 Bbl/d $61.25 put 35,500 Bbl/d $66.15 call 1,000 Bbl/d $61.25 swap $60 $55 $50 30,500 Bbl/d $52.38 put 3,000 Bbl/d $50.00 put $45 $40 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Hedge book started at zero post spin target hedges on 50% of production Strategy focuses on protecting cash flow for capital investments and covenant compliance Hedge transactions completed with multiple counterparties We also have natural gas hedges in place for 4Q15 for 40,000 MMBtu/d at $3.01 per MMBtu as well as a collar transaction for 20,000 MMBtu/d with a weighted average floor of $2.80 per MMBtu and a ceiling of $3.17 per MMBtu. * - As of November 3, 2015 20
Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Jan-21 Jul-21 Jan-22 Jul-22 Jan-23 Jul-23 Jan-24 Jul-24 Focus on Balance Sheet Capitalization as of 9/30/15 ($MM) Senior Unsecured RCF 1 481 Senior Unsecured Term Loan 1,000 Senior Unsecured Notes 5,000 Total Debt 6,481 Less cash and deferred financing costs (65) Total Net Debt 6,416 Equity 2,355 Total Net Capitalization 8,771 Total Net Debt / Net Capitalization 73% Total Net Debt / LTM Adjusted EBITDAX 5.7x LTM Adjusted EBITDAX / Interest Expense 2 3.5x PV-10 3 / Total Net Debt 2.51x Total Net Debt / Proved Reserves ($/Boe) $8.35 Total Net Debt / PD Reserves ($/Boe) $11.62 Total Net Debt / Production ($/Boepd) $40,352 1 We have the ability to incur total borrowings of $2.0 billion less outstanding amounts subject to compliance with our quarterly financial covenants which currently limit our ability to utilize the full amount. 2 Assumes full year interest expense at indicated debt levels and current interest rates. 3 PV-10 as of 12/31/14 based on SEC five-year rule applied to PUDs using SEC price deck. Deleveraging is a priority November credit facility amendment provides additional financial flexibility Ratings action initiated transition to secured borrowing base facility New secured borrowing base was established at $3.0 billion and currently has approximately $1.5 billion outstanding Debt Maturities ($MM) $2,500 $2,000 $1,500 $1,000 $500 $0 $25 Term Loan $625 $1,000 $1,750 $2,250 21
Approved Credit Facility Amendment Provides Additional Financial Flexibility Lender group approved several amendment provisions to provide CRC additional flexibility to manage our business through the challenging commodity price environment Amended financial covenants that revert to original covenants once outside of the borrowing base period Consolidated First Lien Senior Secured Leverage Ratio Consolidated Interest Expense Ratio Other amendment changes Permitted second lien basket of $2.25 billion with excess cash sweep of amounts > $250 million Basket carveouts for contemplated transactions which permit up to 50% of net proceeds to potentially repurchase junior debt; the remaining 50% is required to be used to repay outstanding term loans. Facility contemplates the monetization of midstream assets with no reduction to the borrowing base Consolidated leverage ratio Consolidated interest expense ratio Borrowing Base Period: Maximum First Lien Leverage Ratio : 2.25x Minimum Interest Expense Ratio : 2.0x Pathway to Investment Grade: Maximum Total Leverage Ratio: 4.50x Minimum Interest Expense Ratio : 2.5x 22
4Q15 Guidance Anticipated Realizations Against the Prevailing Index Prices for 4Q15 Oil 86% to 90% of Brent NGLs 36% to 40% of Brent Natural Gas 93% to 97% of NYMEX Production, Capital and Income Statement Guidance Production 151 to 156 Mboe per day Capital $90 to $100 million Production Costs $16.75 to $17.25 per boe G&A $4.85 to $5.05 per boe DD&A $17.40 to $17.60 per boe Taxes other than on income $38 to $42 million Exploration expense $6 to $10 million Interest expense $82 to $84 million Income tax expense rate 40% Cash tax rate 0% 23
Poised to Take Advantage of a Commodity Price Recovery World-Class Resource Base: Large inventory of assets across basins and drive mechanisms that provide strong returns through the commodity price cycle Exceptional Operating Leverage: High level of operating leverage and control favorably positions CRC to capitalize on a strengthening commodity market Stable Base: Diverse and stable assets enable a predictable production profile with low base declines Sacramento Basin 19 MMBoe Proved Reserves 7 MBoe/d production San Joaquin Basin 525 MMBoe Proved Reserves 111 MBoe/d production Ventura Basin 58 MMBoe Proved Reserves 10 MBoe/d production Focused and Experienced Management Team: Proactive executive team that swiftly executes strategic objectives NY00813G / 589203_1.WOR Los Angeles Basin 166 MMBoe Proved Reserves 33 MBoe/d production Reserves as of 12/31/14; Production figures reflect average YTD 2015 rates. 24
California Resources Corporation Appendix 25
Non-GAAP Reconciliation for Adjusted EBITDAX For the Third Quarter Ended September 30, For the Nine Months Ended September 30, Full Year ($ in millions) 2015 2014 2015 2014 2014 Net Income/(loss) ($104) $188 ($272) $657 ($1,434) Interest expense 82-244 - 72 Income taxes expense/(benefit) (50) 131 (165) 444 (987) Depreciation, depletion and amortization 253 304 757 886 1,198 Exploration expense 5 25 29 71 139 Asset Impairments (a) - - - - 3,402 Other (b) 26 14 87 36 158 Adjusted EBITDAX $212 $662 $680 $2,094 $2,548 Net cash provided by operating activities $180 $631 $412 $1,867 $2,371 Interest expense 82-244 - 72 Cash income taxes - 47-182 165 Cash exploration expenses 3 6 20 19 38 Changes in operating assets and liabilities (7) (35) 43 12 (143) Other, net (46) 13 (39) 14 45 Adjusted EBITDAX $212 $662 $680 $2,094 $2,548 a - For full year 2014, includes pre-tax impairment charges of $3.4 bn. b - Includes non-cash and unusual or infrequent charges. 26
Non-GAAP Reconciliation for PV-10 ($ in millions) At December 31, 2014 PV-10 $16,091 Present value of future income taxes discounted at 10% (5,263) Standardized Measure of Discounted Future Net Cash Flows $10,828 PV-10 is a non-gaap financial measure and represents the year-end present value of estimated future cash inflows from proved oil an natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserve bases and the reserve bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity. 27
Non-GAAP Reconciliation for Adjusted EPS For the Third Quarter Ended September 30, For the Second Quarter Ended June 30, For the Nine Months Ended September 30, ($ in millions) 2015 2014 2015 2015 2014 Net Income/(loss) $(104) $188 $(68) $(272) $657 Hedge related gains (53) - 17 (33) - Early retirement and severance costs 62-10 72 - Rig terminations and other costs 3-1 6 - Tax related adjustments 6 - (11) (7) - Adjusted net income / (loss) $(86) $188 $(51) $(234) $657 EPS diluted $(0.27) $0.48 $(0.18) $(0.71) $1.69 Adjusted EPS diluted $(0.22) $0.48 $(0.13) $(0.61) $1.69 Weighted average diluted shares outstanding (a) 383.8 381.8 382.7 382.7 381.8 (a) On November 30, 2014, the Spin-off date from Occidental Petroleum Corporation, we issued 381.4 million shares of our common stock. Additional shares were distributed to our employees and vested in December. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed these amounts to be outstanding for each period prior to the Spin-off. 28
Value Creation Index Measures value created per dollar investment ( Bang for the buck ) Corporate Target 1.3 VCI = PV10 pre-tax cash flows PV10 of investments Project A Project B Project C Max IRR% Max VCI Max NPV Period Capital Cash Flow Capital Cash Flow Capital Cash Flow 0 1,000 (1,000) 1,000 (1,000) 2,500 (2,500) 1-1,100-125 - - 2-200 - 250 - - 3-100 - 500 - - 4-50 - 600 - - 5 - - - 700-5,000 1,000 450 1,000 1,175 2,500 2,500 NPV-10 $250 NPV-10 $491 NPV-10 $550 VCI-10 1.27 VCI-10 1.54 VCI-10 1.24 IRR 33% IRR 24% IRR 15% 29