FIRST QUARTER 2018 EARNINGS REVIEW. Todd Stevens President & CEO May 3, 2018 Mark Smith Senior EVP & CFO

Transcription

1 FIRST QUARTER 2018 EARNINGS REVIEW Todd Stevens President & CEO May 3, 2018 Mark Smith Senior EVP & CFO

2 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 include those regarding our expectations as to our future: financial position, liquidity, cash flows and results of operations operations and operational results including production, hedging and capital business prospects investment transactions and projects budgets and maintenance capital requirements operating costs reserves Value Creation Index (VCI) metrics are based on certain estimates type curves including future production rates, costs and commodity prices 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. We also believe third- party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. 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 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 or storage 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 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. See the Investor Relations page at for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio calculations, and drilling locations. 1Q 2018 Earnings 2

3 1Q 2018 Highlights Continued Forward Progress ACTIVITY 9 Rigs Maintained Sustainable Level of Activity PRODUCTION 123 Mboe/d ~2% Sequential Quarter Decline Capital Adj. EBITDAX* $139 Million Entirely Internally Funded $250 Million ~8% Sequential Quarter Growth * See the Investor Relations page at for a reconciliation to the closest GAAP measure and other important information. 1Q 2018 Earnings 3

4 Resilient Resource Base MBoe/d Capital ($MM) Net Production By Stream (Mboe/d) Oil NGL Gas Total Capital* CRC Capital (Internally Funded) Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18E** 0 *Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as all JV partners which include BSP and MIRA. Please note our consolidated financial statements include BSP s investment and exclude MIRA s investments based on the accounting treatment of each venture. ** Q2 Capital guidance includes CRC, BSP, and MIRA capital 1Q 2018 Earnings 4

5 $MM Flattening Production while Growing Adjusted EBITDAX Margins Field Production 1 Adjusted EBITDAX Field Oil Production Field Gas & NGL Production Incremental Elk Hills Production Q Guidance Range Adj. Due to Accounting Change Adj. EBITDAX Margin Adj. EBITDAX 70% 60% % % % 80 20% Q Q Q Q Q Q Q Q Q Q2 2018E 40 10% CRC arrested oil decline and is growing Adjusted EBITDAX 0 Q Q Q Q Q Q Q Q Q % 1 Field Production includes gross production from the Wilmington field, which is subject to PSCs, and net production from all other assets. 1Q 2018 Earnings 5

6 Elk Hills Transaction Summary Total Consideration $460MM Cash MM Shares 2017 Net Production 13 Mboepd 46% Oil 9% NGL 2017E Operating Cash Flow $65 Brent 2017 Proved Reserves 64 Mmboe CRC SEC 2017 Pricing CRC acquired Chevron s non-operated working interest ranging between 20% to 22% in different producing horizons within the Elk Hills field for total consideration of $460MM in cash and 2.85 MM CRC shares, effective April 1, 2018 CRC now owns Elk Hills in fee simple, holding 100% WI, NRI, and surface lands Acquired ~10,000 surface fee acres Elk Hills Unit 47,000 acres Existing CRC Surface Acreage Acquired Surface Acreage Elk Hills Unit CRC now owns 100% WI, NRI and surface in its largest field 1Q 2018 Earnings 6

7 $MM Accelerating Value Further from Midstream JV $150 $100 $50 ARES Cash Distributions 1 Cost Synergies Avoided Interest Cash Flow from Acquired Assets Acquired assets will add an incremental $40MM- $50MM of cash flow/ saving per year for the first 36 months 1 Expect to achieve $5MM of annualized operational savings within 6 months of closing and ~$15MM of additional synergies within the next 18 months Consolidate Operations Streamline business processes Increased revenue opportunities Improve CRC capital efficiency Maximizes NGL yields and revenue through increased utilization of CRC s best-in-class cryogenic plant $- ARES TRANSACTION INCREMENTAL CASH FLOW Elk Hills Transaction delivers incremental cash flow for investment in 1.7+ VCI inventory Transaction reduces CRC s per unit production costs by ~$0.55/boe and SG&A by ~$0.20/boe Elk Hills produces light oil with an avg API of ~36, which has received a premium over Brent in recent months 1 Assumes the PIK portion of the Ares distributions are deferred for the first 36 months. 1Q 2018 Earnings 7

8 2018 Capital Investment Program Transitioning to Mid-Cycle Commodity Prices Production Enhancement Plans for 2018 CRC 2018 capital plan will be directed to oil-weighted projects in our core fields: Elk Hills, Wilmington, Kern Front, Huntington Beach, and continued delineation of Buena Vista, Ventura and Southern San Joaquin Areas JV capital will be focused in the San Joaquin Basin and Huntington Beach We have a dynamic plan that can be scaled up or down depending on the price environment and efficient deployment of joint venture proceeds Increased 2018 capital plan due to recent Elk Hills transaction and cash flow outlook Development Facilities 2018E Total Capital Plan Approx. $550 to $600 million Exploration 21% 3% 42% Drilling 2018E Development Capital By Drive Approx. $375 million Steamfloods Unconventional 13% 10% 44% Conventional At $55 flat Brent and $3 NYMEX, the fully-burdened CRC Development Program delivered a 1.7 VCI or 30% IRR E Development Capital By Basin Approx. $375 million Ventura 6% 27% Los Angeles Workover 16% 18% JV - Capital Waterfloods 29% 4% Exploration San Joaquin 67% 1 Facility Costs and other non-return capital are apportioned to producing wells in the year they are drilled. 2 IRR estimate for the 2017 development program. VCI is calculated by dividing the net present value of the project s expected pre-tax cash flow over its life by the net present value of the investments, each using a 10% discount rate. 1Q 2018 Earnings 8

9 Portfolio Flexibility Provides Range of Crude Oil Scenarios Oil Production MB/d Adjusted EBITDAX $MM Capital ($MM) Combined with mid-cycle commodity prices, we are positioned for growth in: Cash flow Production Reserves in total and on a debt-adjusted per share basis* ,400 2,000 1,600 1, Estimated Crude Oil Production Outcomes E 2019E 2020E 2021E Estimated Range of Adjusted EBITDAX Outcomes Portfolio Planning Scenarios Portfolio Planning Scenarios Capital focused on oil projects that provide Increasing Margins Low Decline Rates + = Compounding Cash Flow 1,800 1,500 1, Estimated Ranges of Capital Investments E 2019E 2020E 2021E Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes varying lease operating costs within historical ranges depending on the commodity prices of the planning scenario outcomes. Ranges of portfolio planning scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. All discretionary cash flow is reinvested in business in 2019 and beyond for each scenario. Please see end notes for further information regarding Adjusted EBITDAX. * See the Investor Relations page at for a description of the calculation of the debt-adjusted per share basis and other important information. 1Q 2018 Earnings 9

10 CRC Price Realizations % of WTI & Brent $/Bbl $/Mcf Oil Price Realization (with Hedges) % 30-80% 60% 40% 20% 0% $49.19 $ % 37% WTI Realizations Brent $53.64 $43.32 $45.04 WTI 52% 50% $42.01 Brent $54.82 $51.24 $ % $67.18 $ Q 2018 Realization % of WTI 101% 99% 97% 100% NGL Price Realization - % of WTI & Brent 69% 65% 64% Q 2018 $62.87 Gas Price Realization $2.75 $2.66 NYMEX $2.42 $2.28 Realizations $3.09 $2.67 $ Q 2018 Realization % of NYMEX 97 % 94% 86% 98%* $2.81 * California refinery demand for native crude continues to be strong and reduction in heavy waterborne crude has positively influenced differentials. NGL prices have been supported by lower inventories and export markets. CRC believes near-term differentials will remain strong *See attachment 6 of the Earnings Release for information regarding the effects of an accounting change on realized natural gas prices. 1Q 2018 Earnings 10

11 Strong Cash Flow Growth Operating Cash Flow $ MM 250 1Q17 Volume* Price* Costs Interest Working Capital and Other 1Q * Includes effects of PSCs 1Q 2018 Earnings 11

12 Living Within Cash Flow $ MM Annual Quarterly FY 2016 FY Q Adj. EBITDAX Operating Cash Flow Capital Investment 1 See the Investor Relations page at for a reconciliation to the closest GAAP measure and other important information. 2 Does not include JV capital. Net of capital-related accruals. 1Q 2018 Earnings 12

13 Quarterly Cost Comparison 1Q17 4Q17 1Q18 Production costs ($/Boe) Production costs excluding PSC effects ($/Boe) Taxes other than on income ($MM) Exploration expense ($MM) Interest expense ($MM) $17.70 $19.64 $19.08 $16.66 $18.31 $17.47 $33 $33 $38 $6 $5 $8 $84 $91 $92 1Q 2018 Earnings 13

14 1Q18 Results Summary Comparison 1Q17 4Q17 1Q18 Earnings (Loss) per Share - Diluted $1.22 ($3.23) ($0.05) Adjusted Earnings (Loss) per Share Diluted* ($1.02) ($0.33) $0.18 Oil Production 86 MBbl/d 80 MBbl/d 77 MBbl/d Total Production 132 MBoe/d 126 MBoe/d 123 MBoe/d Realized Oil Price w/ Hedge ($/Bbl) $50.24 $56.92 $62.77 Realized NGL Price ($/Bbl) $34.33 $44.03 $43.13 Realized Natural Gas Price ($/Mcf) $2.90 $2.77 $2.81 Net Income (Loss) Attributable to Common Stock $53 MM ($138) MM ($2) MM Adjusted EBITDAX* $200 MM $231 MM $250 MM Capital Investments $50 MM $139 MM** $139 MM Cash Flow from Operations $133 MM $23 MM $200 MM * See the Investor Relations page at for a reconciliation to the closest GAAP measure and other important information. ** 4Q 2017 Includes $14MM of BSP funded capital 1Q 2018 Earnings 14

15 Recent Transactions - Improving Debt Metrics Pro Forma Capitalization 1 ($MM) 3/31/2018 Actual Elk Hills (EH) Transaction April Debt Repurchases 3/31/2018 Pro Forma 1 1st Lien 2014 Revolving Credit Facility (RCF) $ - $ - $ 45 $ 45 1st Lien 2017 Term Loan 1,300 1,300 1st Lien 2016 Term Loan 1,000 1,000 2nd Lien Notes 2,248 (95) 2,153 Senior Unsecured Notes Total Debt 4,941 - (50) 4,891 Less cash (494) Total Net Debt 4, (16) 4,891 Mezzanine Equity Equity 2 3 (654) 51 (603) Total Net Capitalization $ 4,517 $ 511 $ (16) $ 5,012 $4,000 $3,000 $2,000 Pro Forma Total Debt $4.89B Pro Forma 1 Debt Maturities ($MM) 2nd Lien Notes 2014 RCF Unsecured Notes 2016 Term Loan 2017 Term Loan Total Debt / Total Net Capitalization 109% 98% Total Debt / LTM Adjusted EBITDAX 4 6.0x 5.4x LTM Adjusted EBITDAX 4 / LTM Interest Expense 2.4x 2.6x PV-10 5 / Total Debt 0.9x 1.1x Total Debt / Proved Reserves 6 ($/Boe) $8.00 $7.17 Total Debt / Proved Developed Reserves 6 ($/Boe) $11.23 $10.05 Total Debt / 1Q18 Production ($/Boepd) $40,171 $36,230 $1,000 $ Please see end notes for further information regarding the presentation of pro forma financial information. 2 Includes $109 million of noncontrolling interest equity for BSP and Ares. 3 Calculated using 2.85 million shares of CRC common stock at closing share price of $18.06 on 4/9/ Please see end notes for further information regarding Adjusted EBITDAX. 5 PV-10 as of 12/31/2017. PV-10 on a pro forma basis includes an estimate of the Elk Hills reserves acquired at SEC 2017 pricing. See the Investor Relations page at for details on this calculation. 6 Reserves as of 12/31/2017. Reserves on a pro forma basis include an estimate of the Elk Hills reserves acquired. 1Q 2018 Earnings 15

16 2Q18 Guidance Anticipated Realizations Against the Prevailing Index Prices for 2Q18 Oil 94% to 98% of Brent NGLs 52% to 56% of Brent Natural Gas 81% to 85% of NYMEX Production, Capital and Income Statement Guidance Production at $67 Brent 133 to 138 Mboe/d Production at $74 Brent 131 to 136 Mboe/d Capital $165 to $185 million Production Costs at $67 Brent $17.90 to $19.40 per Boe Production Costs at $74 Brent $18.10 to $19.60 per Boe Adjusted G&A* $6.45 to $6.75 per Boe DD&A* $10.30 to $10.60 per Boe Taxes other than on income $34 to $38 million Exploration expense $7 to $11 million Interest expense $91 to $95 million Cash Interest $150 to $154 million Income tax expense rate 0% Cash tax rate 0% * Guidance assumes production at $74 Brent levels 1Q 2018 Earnings 16

17 Opportunistically Built Oil Hedge Portfolio Strategy Protect cash flow for capital investments and covenant compliance 2Q Q Q Q Q Q Q 2019 Sold Calls Barrels per Day 6,200 6,100 16,100 16,100 6,000 1,000 1,000 Weighted Average Ceiling Price per Barrel $60.24 $60.24 $58.91 $65.75 $67.01 $60.00 $60.00 Purchased Calls Barrels per Day , Weighted Average Ceiling Price per Barrel $ Purchased Puts Barrels per Day 1,200 6,100 1,100 29,100 21,000 11,000 1,000 Weighted Average Floor Price per Barrel $ $60.86 $62.40 $63.27 $45.85 Sold Puts Barrels per Day 29,000 24,000 19,000 30,000 15,000 10,000 - Weighted Average Floor Price per Barrel $45.00 $46.04 $45.00 $49.17 $50.00 $ Swaps Barrels per Day 44,400 19,000 19,000 7, Weighted Average Price per Barrel Percentage of 2Q 2018 Oil Production Hedged* $60.00 $60.13 $60.13 $ % 30-31% 24-25% 43-45% 25-26% 13-14% 1% We target hedges on 50% of crude oil production As of 4/10/2018. Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and $70 Brent. * Assumes future counterparty options are not exercised. Refers to guidance at $74 Brent. 1Q 2018 Earnings 17

18 Significant Reduction in Total Debt from Post-Spin Peak Total Debt ($ MM) Chose options to maximize deleveraging and minimize recurring cost to the income statement on a per share basis. Continue to seek opportunistic transactions that reduce overall debt. 7,000 6,000 5,000 6, Debt Repurchases $97MM 4,000 Closed 2 transactions 4,891 3,000-2Q15 Debt Exchange for 2L Open Market Repurchases Equity for Debt Exchange Cash Tender for Unsecureds Cash Flow Ares & Elk Hills Transactions 3/31/2018 Pro 2 Forma Total Total Debt Reduction $535 million $205 million $102 million $625 million $110 million $297 million $1,874 million 1 Represents mid-second quarter 2015 peak debt. 2 Please see end notes for further information regarding the presentation of pro forma financial information. 1Q 2018 Earnings 18

19 Wilmington Production Sharing Contracts Effect of Oil Price on Net Production Over 25% of CRC s oil production is subject to Production Sharing Contracts PSC Mechanics Gross Production CRC pays our partners share of the Operating and Capital Cost CRC recovers our partners portion of the cost in barrels CRC receives 45-49% of the gross production as Profit Barrels Cost Recovery Bbls As prices rise, fewer barrels are required to recover our partners portion of the cost Net Profit Bbls 45-49% of Gross Production Higher oil prices result in higher cash flow, but lower net production Realized Price ($/Boe) 1Q 2018 Earnings 19

20 Wilmington Field Production Sharing Contract Boe/d Boe/d Over 90% of CRC s Long Beach production is covered under Production Sharing Contracts (PSCs) with the State and the City of Long Beach CRC s net production decreases when prices rise and increases when prices decline Base rate/profit are defined in contracts State/City receive most of base profit 50,000 40,000 30,000 20,000 10,000 - Base Profit Split: 4% CRC / 96% State* LBU PSC Base Incremental Profit Split: 49% CRC / 51% State* Incremental End of LBU Base CRC receives remainder Incremental rate/profit is everything greater than the Base Per the provisions of the contract, the Base of the LBU PSC ended in 4Q 2016 *Average profit split %. 12,000 10,000 8,000 6,000 4,000 2,000 - Tidelands PSC First of 3 new PSC s executed Base Profit Split: 4% CRC / 96% State* Base Incremental Incremental Profit Split 49% CRC / 51% State & City* 1Q 2018 Earnings 20

21 Brent Crude Oil Price ($/Bbl)* History of Proactive Strategic Decisions CRC Drilling Rig Count Swift, decisive actions through the commodity downturn have positioned CRC for growth. Proactive discussions with lenders and solid asset base provide a path to recovery and an actionable inventory. $120 $100 1 Oil Price CRC Rig Count $80 $60 $40 $20 Under OXY SPIN-OFF $0 07/20/14 11/20/14 03/20/15 07/20/15 11/20/15 03/20/16 07/20/16 11/20/16 03/20/17 07/20/17 11/20/17 03/20/18 07/20/ Cut rig count/began hedging 4. Deleveraging Transactions 2. Cut 2015 Capital Budget 5. Increasing activity, invest within Cash Flow 3. Bank Amendments 6. JV Transactions 1Q 2018 Earnings 21

22 ($Billion) Elk Hills Acquisition Enhances 2017 Reserves 1 Value Further Above EV $20 $16 $12 Infrastructure 2 Surface & Minerals 3 $8 $4 Unproved 4 Proved Value PDP Value Current EV of $6.0 Bn 5 $0 $55 Brent $65 Brent $75 Brent 1-5 See endnotes in the Appendix. See the Investor Relations page at for important information about 3P reserves and other hydrocarbon quantities. 1Q 2018 Earnings 22

23 The Case for CRC: Investment Thesis Overview $MM Investment Case for CRC Competitive Advantages World-class assets with significant inventory Resilient model that preserves optionality and protects downside Focused on value and poised for growth Grow within cash flow Clear runway and available cash Industry leading decline rate Integrated and complementary infrastructure Why Own CRC Now Moved from defense to offense Disciplined portfolio management 2,500 Potential for Adj. EBITDAX growth* Maintain Production Production and Cash Flow Growth 2,000 1,500 1, E 2019E 2020E 2021E E 2019E 2020E 2021E Production Innovation Deep Inventory *See Slide 9 for additional information regarding Adjusted EBITDAX Growth planning scenarios. 1Q 2018 Earnings 23

24 Appendix

25 Development Capital ($B) Full Cycle Cost 2 ($/Boe) Deep Inventory of Actionable Projects at $65 Brent Portfolio Spectrum Growth portfolio focus, fully burdened All projects meet a Value Creation Index (VCI) 1 threshold of 1.3 at $65 Brent and $3.00 NYMEX, and deliver robust cash flow Steamflood Waterflood Primary Shale Gas Portfolio has large contributions from all recovery mechanisms and reserves types Many projects take advantage of existing infrastructure, while other newer projects may require infrastructure investment in facilities and sales points 1 For further information on how VCI is calculated please see the end notes. 2 Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than on income. 3 See the Investor Relations page at for details regarding net resources Net Resources 3 (MMBoe) Net Resources 3 (MMBoe) 1Q 2018 Earnings 25

26 Accelerating Value and Derisking Inventory through JVs Highlights: Highlights: Up to $250MM over ~2 years o Two tranches of $50MM o o Total of $100MM funded Third tranche expected in Q2 Investor funds 100% of project capital in exchange for a net profits interest (NPI) o Investor NPI interest reverts to CRC after low teens target IRR o CRC retains early termination options Current focus is in the San Joaquin Basin CRC operates all wells Up to $300MM o Initial commitment of $160MM DrillCo type structure where Investor funds 100% of project capital for 90% WI, with CRC carried on its 10% WI o CRC interest reverts to 75% after target IRR is achieved o CRC retains early termination options Focus on four fields within the San Joaquin Basin o Kern Front, Mt. Poso, Pleito Ranch, Wheeler Ridge CRC operates all wells 1Q 2018 Earnings 26

27 Typical Industry JV Structure Production Based on recent industry JV deals, a typical deal structure is o Partner pays % Capital o Receives % Working Interest o Typical hurdle rate: o 10% - 20% IRR o Partner s working interest once hurdle rate is achieved: o 5% - 25% 7, , , , , Hurdle Rate Reached 2, , JV Share Typical E&P Share Time 1Q 2018 Earnings 27

28 Strategic Partner Alignment Partner Affiliate of Ares Management (Ares) Summary of Deal Contributed Assets Elk Hills power plant, gas processing assets and related non-borrowing base infrastructure currently owned by CRC Midstream JV Capitalization Class A common interests (voting) owned 50% by Ares and 50% by California Resources Elk Hills (CREH) Class B preferred interests ( Preferred ) owned 100% by Ares Class C common interests (distributing) owned 95.25% by CREH and 4.75% by Ares Distribution to Partners Exit Provisions Preferred interests to receive distributions of 13.5% per annum on the $750 MM contributed amount 9.5% cash pay and 4.0% PIK to be deferred for the first three years Deferred distributions are interest bearing and repaid over two years following the deferral period Remaining cash after preferred distributions to be distributed pro rata to Class C interests Prior to end of 5 or 7.5 years, CRC may redeem Preferred at variable amounts that include make whole premiums At end of 5 years, CRC may elect to either redeem or extend to 7.5 years At 7.5 years, if not redeemed by CRC, Preferred can monetize the JV Board Board of Managers to consist of three CRC representatives and three representatives from Ares 1Q 2018 Earnings 28

29 CRC Midstream JV Structure with Ares Benefits Strategic alignment with Ares Provides CRC paths for opportunistic deleveraging through cash flow growth or debt reduction Greatly enhances liquidity California Resources Elk Hills, LLC Retain ownership and operational control Defined exit criteria Power and Gas Processing Services Contributed Assets $750 MM gross proceeds Class A (50%) and Class C (95.25%) Common Interests Commercial Agreement Capacity Charges Elk Hills Power, LLC $750 MM gross proceeds Ares Management, L.P. Class B Preferred Interests, Class A and Class C Common Interests 1Q 2018 Earnings 29

30 MMBoe Value Additive Inventory Growth Comprehensive technical review of 40% of CRC s fields proved reserves of 618 million BOE and 450 million BOE of probable reserves. 119% organic reserve replacement, excluding the effect of price adjustments. We added 34 million BOE of proved reserves from extensions and discoveries and 22 million BOE from performance. We were also able to rebook 49 million BOE due to the increase in prices compared to prior years. Organic F&D costs excluding price related revisions were $6.82 per BOE and produced a recycle ratio of 2.1x. Over 95% of our total proved reserves have been audited by Ryder Scott in the last three years. 2,250 2,000 1,750 1,500 1,250 1, P Reserves Growth Since Spin 321 >350% Growth , Spin-off See the Investor Relations page at for important information about 3P reserves and other hydrocarbon quantities. Unproven Revisions Due to Price Since 2014 Proven Cumulative Production 1Q 2018 Earnings 30

31 End Notes From Slide 22 1 Current CRC estimate of reserves value as of December 31, 2017, including reserves acquired in the Elk Hills transaction. Includes field-level operating expenses and G&A. Assumes $3.00/MMBTU NYMEX. 2 Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated to exceed the burden on reserves that would be incurred if assets were monetized. Excludes the value of the assets monetized in the Ares transaction. 3 Surface & Minerals reflect the estimated value of undeveloped surface and minerals held in fee. 4 Unproved inventory comprises risked probable and possible reserves and contingent and prospective resources. Contingent and prospective resources consist of volumes identified through life-of-field planning efforts to date. 5 Calculated using a market cap as of 4/20/2018 and the 3/31/2018 Pro Forma debt adjusted for the Elk Hills transaction and the April debt repurchases. Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior four-year time period. Drive mechanism type curves are the weighted average of the field-specific curves related to the projects chosen for our near-term growth plan. Type curves represent management s estimates of future results and are subject to project selection and other variables. Our type well curves are prepared for purposes of modeling overall results of our near-term growth program and are not useful for purpose of benchmarking any individual well or pattern performance. Actual results are expected to vary depending on which projects are specifically developed. Value Creation Index (VCI) Note: VCI is calculated by dividing the net present value of the project s expected pre-tax cash flow over its life by the net present value of project investments, each using a 10% discount rate. Adjusted EBITDAX Note: The 3/31/2018 Pro Forma Adjusted EBITDAX includes a +$20 million adjustment as a result of the Elk Hills transaction and no adjustment as a result of the April debt repurchases. See the table to the right for a reconciliation to the closest GAAP measure. See the Investor Relations page at for other important information. Pro Forma Financial Information and Elk Hills Transaction Note: The actual amount of drawings under our revolver necessary to complete the Elk Hills transaction and the April debt repurchases will depend on the actual amount of cash available at the closing date. The pro forma information in this presentation does not take into account capital expenditures or changes in our business since 3/31/2018 other than the Elk Hills transaction and April debt repurchases. The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-gaap financial measure of Adjusted EBITDAX. (in millions) 3/31/2018 Elk Hills Transaction 3/31/2018 Pro Forma Net income (loss) $ 9 $ 20 $ 29 Interest and debt expense, net Depreciation, depletion and amortization Exploration expense 8 8 Unusual, infrequent, and other items Other non-cash items Adjusted EBITDAX $ 250 $ 20 $ 270 1Q 2018 Earnings 31