Mark Smith | Senior Executive Vice President & CFO | Orlando, FL | March 5, 2018
Raymond James & Associates
39 th Annual Institutional Investors Conference Mark Smith | Senior - - PowerPoint PPT Presentation
Raymond James & Associates 39 th Annual Institutional Investors Conference Mark Smith | Senior Executive Vice President & CFO | Orlando, FL | March 5, 2018 Forward Looking / Cautionary Statements This presentation contains forward-looking
Mark Smith | Senior Executive Vice President & CFO | Orlando, FL | March 5, 2018
Raymond James & Associates
Raymond James and Associates 39th Annual Institutional Investors Conference | 2
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: 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: 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 www.crc.com Investor Relations for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio calculations, and drilling locations.
including future production rates, costs and commodity prices
investment
ventures
completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or
transportation, marketing and sale of our products
projects or acquisitions or higher-than-expected decline rates
constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
available on our website at crc.com.
Raymond James and Associates 39th Annual Institutional Investors Conference | 3 500 1,000 1,500 2,000 2,500
2017 2018E 2019E 2020E 2021E
$MM
Investments and Deploying Rigs
Deleveraging
Crude Oil
*See Slide 22 for additional information regarding EBITDAX Growth planning scenarios.
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Sacram amento ento Basin in 14 MMBOE Proved Reserves 6 MBOE/d production (100% dry gas) San Joaquin uin Basin in 419 MMBOE Proved Reserves 90 MBOE/d production (58% oil) Ventur ura a Basin in 40 MMBOE Proved Reserves 6 MBOE/d production (63% oil)
cash flow and drive growth
increases flexibility
Reserves as of 12/31/17; Production figures reflect average FY 2017 rates.
Los Angel eles Basin in 145 MMBOE Proved Reserves 27 MBOE/d production (100% oil)
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25 50 75 100 125 150 175 200 20 40 60 80 100 120 140 160 180 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 FY 2015 FY 2016 FY 2017 Capita ital l ($MM) MBoe/d /d
)
Oil NGL Gas Total Capital Internally Funded Capital
Note: Capital and production for 2017 include BSP’s investment and exclude MIRA’s investment.
Total Capital: $75MM $401MM $371MM* Internally Funded Capital: $275MM
Raymond James and Associates 39th Annual Institutional Investors Conference | 6 Drilling 24% Workover 18% BSP JV Capital 22% MIRA JV Capital 14% Exploration 2% Other1 6% Development Facilities 14%
Ranch, Wheeler Ridge and the delineation of Kettleman North Dome
Total: $429 million3
1Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments. 2Facility Costs and other non-return capital are apportioned to producing wells in the year they are drilled. 3Includes capital funded by MIRA, which is not included in our consolidated results.
2017 Total al Capital tal In Inve vest sted ed
1.70 2.00 30% 45% 0% 10% 20% 30% 40% 50% 0.00 0.50 1.00 1.50 2.00 2.50 $55 Brent Flat $3 NYMEX $55 Brent 2017, $65 Brent in 2018+ & $3 NYMEX
IRR VCI
VCI IRR
Results lts of Full lly-Burde urdened ed2 2017 CRC Deve velopm lopment ent Pro rogr gram am
Total: ~$240 million
Other1
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$260 MM Committed
Gross Peak Production per $100 MM of development capital
Potential Targeted Reserves per $100 MM of development capital
JVs are generally focused in the San Joaquin Basin
Total Potential JV Capital
Kern Front
Oxy Land Oil Fields Gas Fields
Buena Vista Pleito Ranch Elk Hills Kettleman North Dome Lost Hills Mt Poso
CRC Land
Portfolio Flexibility and Optionality Enables High Margin Production Growth Accelerate Value Derisk Inventory
JVs add production and cashflow, and help de-risk inventory to increase CRC’s reserve base
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$100 $100 $193 $2,250 $1,000 $1,300 $0
$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18 Mar-19 Jun-19 Sep-19 Dec-19 Mar-20 Jun-20 Sep-20 Dec-20 Mar-21 Jun-21 Sep-21 Dec-21 Mar-22 Jun-22 Sep-22 Dec-22 Mar-23 Jun-23 Sep-23 Dec-23 Mar-24 Jun-24 Sep-24 Dec-24 2014 RCF 2017 Term Loan 2016 Term Loan 2nd Lien Notes Unsecured Notes
$150 million minimum liquidity
financial covenants
1st Lien 2014 Revolving Credit Facility (RCF)
1,300 1st Lien 2016 Term Loan 1,000 2nd Lien Notes 2,250 Senior Unsecured Notes 393 Total Debt 4,943 Less cash2 (441) Total Net Debt 4,502 Equity3 (764) Total Net Capitalization 3,738 Total Net Debt / Total Net Capitalization 120% Total Net Debt / LTM Adjusted EBITDAX4 5.9x LTM Adjusted EBITDAX4 / LTM Interest Expense 2.2x PV-105 / Total Net Debt 1.0x Total Net Debt / Proved Reserves ($/Boe) $7.28 Total Net Debt / Proved Developed Reserves ($/Boe) $10.23 Total Net Debt / 2017 Production ($/Boepd) $34,899
Pro ro-Forma ma1 Capital talization zation ($MM) Pro ro-Forma1 Debt t Matur uriti ties es ($MM)* )*
1 Pro-forma capitalization table and debt maturities graph reflect the payoff of the 12/31/17 outstanding balance
2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426
million of available cash after the Ares transaction and proforma repayment of the RCF.
3 Excludes noncontrolling interest at 12/31/17 and includes $50 million of equity from the Ares private placement. 4 See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other important
information.
5 PV-10 as of 12/31/17, see Attachment 2 of CRC’s Fourth Quarter Earnings Release dated February 26, 2018 for
details on this calculation. * Previously, the RCF, the 2017 Term Loan and the 2016 Term Loan were subject to springing maturities related to the 2020 and 2021 Notes. During the fourth quarter of 2017, CRC repurchased $65 million in principal amount of the 2020 Notes and $35 million in principal amount of the 2021 Notes, which eliminated the springing maturity feature. The 2017 Term Loan also has a springing maturity related to the 2016 Term Loan.
Undrawn RCF
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BOE of probable reserves.
extension and discoveries and 22 million BOE from
BOE due to the increase in prices compared to prior years.
$6.82 per BOE and produced a recycle ratio of 2.1x.
audited by Ryder Scott in the last three years.
58 109 156 768 644 568 618 222 251 202 321 340 826 1,129 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 Spin-off 2015 2016 2017
MMBoe
Cummulative Production Proven Revisions Due to Price Since 2014 Unproven
>350% Growth
See www.crc.com Investor Relations for important information about 3P reserves and other hydrocarbon quantities.
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Portfolio Spectrum
ly burde dened ed
Creation Index (VCI)1 threshold of 1.3 at $65 Brent and $3.50 NYMEX, and deliver robust cash flow
contributions from all recovery mechanisms and reserves types
advantage of existing infrastructure, while other new projects may require infrastructure investment in facilities and sales points
1VCI is calculated by dividing the net present value of the project’s expected pre-tax cash flow over its life by the net present value of the investments, each using a 10% discount rate. 2Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than on income. 3See www.crc.com, Investor Relations for details regarding net resources.
2 4 6 8 10 100 200 300 400 500 600 700 800 Development Capital ($B) Net Resources3 (MMBoe) 5 10 15 20 25 30 35 40 45 50 100 200 300 400 500 600 700 800 Full Cycle Cost2 ($/Boe) Net Resources3 (MMBoe)
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PDP Value Proved Value Unproved4 $0 $4 $8 $12 $16 $20 $24
$55 Brent $65 Brent $75 Brent ($Billion)
Curren ent EV
.4 Bn5 Infrastructure2 Surface & Minerals3
1-5 See endnotes in the Appendix.
See www.crc.com Investor Relations for important information about 3P reserves and other hydrocarbon quantities.
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Surface & Minerals3
177 154 129 33 26
100 150 200
CRC Chevron USA Aera Energy Sentinel Peak Berry Gross Operated MBoe/d
*Source: DOGGR data (average production data for 2016), IHS, Wood Mackenzie, Company Estimates. * *For non-CRC Companies, estimated 2016 OPEX $/Boe.
Largest 3-D Seismic Position in California
$16 $23 $22 $29 $29
$0 $5 $10 $15 $20 $25 $30 $35 0% 25% 50% 75% 100% CRC Chevron USA Aera Energy Sentinel Peak Berry
OPEX $/Boe** Production Mix
Shallow Deeper (>5,000') FY 2016 OPEX $/BOE**
MONTEREY SANDS AND SHALES TEMBLOR SANDS EOCENE SANDS AND SHALES UPPER CRETACEOUS SANDS AND SHALES 1,000’ PAY TULARE SANDS SHALLOW DEEP ETCHEGOIN SANDS <5,000’ 15,000’
Top California Producers in 2016* Majority of CA Production is Shallow*
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Monterey Formations
25 billion OOIP (BOE) in CRC fields
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1 DOGGR data and U.S. Energy Information Administration.
10 15 20 20 40 60 80 100 120
1998 2000 2002 2004 2006 2008 2010 2012 2014 2016
Rig Count
Net MBOE/d
Net MBOEPD Rig Count
continental U.S.1, >3,000 producing wells
Large fee property position with integrated infrastructure
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FIELDMAP
Growth potential near existing infrastructure
34 21 10 20 30 40 2012-14 2017 Drilling Time Days/well
5.0 2.5 100 200 300 400 500
2.0 3.0 4.0 5.0 6.0 2012-14 2017 Drilling Cost $/Ft Drilling Cost $MM/well Drilling Cost/Well Drilling Cost $/Ft
2017 Conventional BV Nose Development Drilling Cost Average Drilling Days/Well
2017 BV Area development program delivers a 1.8 VCI at a $55 Brent price deck
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quantities of stacked pay
laterally; basin depth (>30,000 ft)
underexplored
risk and proven repeatable technology across huge OOIP fields
liquids)
similar to production-sharing contracts (PSCs). The contracts represented slightly less than 20% of our Total 2017 production.
Wilmington Huntington Beach
33% of CRC’s 2017 oil production is from the Los Angeles Basin
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in California
Waterfloods and Steamfloods
excess of 1,000 BOE/d along Oak Ridge trend
position and existing infrastructure
production by approximately 2,000 BOE/d and production remained affected by approximately 1,000 BOE/d in January 2018
High Growth Area: large OOIP, low recovery factor and potential for high-IP wells
OOIP (MMBO) CUM PROD (MMBO) RF 7,843 813 10%
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the 1970s the use of multifold 2D seismic led to largest discoveries
sands
than 10,000 feet
reservoir geometries
California imports >90% of its natural gas requirements
20 Miles
Raymond James and Associates 39th Annual Institutional Investors Conference | 19 Drilling JV - Capital Workover Development Facilities Exploration Other1 Other1 San Joaquin Ventura Los Angeles
Wilmington, Kern Front, Huntington Beach, and continued delineation of Kettleman North Dome and Buena Vista
and efficient deployment of joint venture proceeds
1Other includes maintenance and occupational health, safety and
environmental projects, seismic and other investments.
2018E Total
tal Pla lan 2018E Dril illing ing Capita tal l – By Drive ive
28% 30% 22% 12% 4%4% 10% 10%
Conventional Exploration Waterfloods Steamfloods Unconventional
42% 6% 30% 16% 80%
The JV capital increases flexibility or provides for incremental deleveraging
6%
2018E Dril illing ing Capita tal l – By Basin in
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0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 0% 10% 20% 30% 40% 50%
PROJECT VCI DISCOUNT ON SECOND LIEN NOTES
PROJECT VS. SECOND LIEN (2L) NOTE REPURCHASE*
INVEST
If the VCI of an investment opportunity falls above the indifference curve, investing in the new project could be a better option
PURCHASE DEBT
If the VCI of an investment opportunity falls below the indifference curve, repurchasing 2L notes could be a better option
Per the terms of the 2014 credit agreement on asset sales, 2L notes must be repurchased at a minimum 20% discount to par Indifference Curve *CRC will continue to review all opportunistic debt reduction transactions. We utilize our Value Creation Index (“VCI”) to guide management in allocating capital and prioritizing investments.
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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.
5 10 15 20 25 30
$0 $20 $40 $60 $80 $100 $120
07/06/14 10/06/14 01/06/15 04/06/15 07/06/15 10/06/15 01/06/16 04/06/16 07/06/16 10/06/16 01/06/17 04/06/17 07/06/17 10/06/17 01/06/18
CRC Drilling Rig Count Brent Crude Oil Price ($/Bbl)*
Oil Price CRC Rig Count
2 1 5 3
Under OXY
6
SPIN-OFF
3 3 3 3 3 4 4 4 4 6 6 3
Raymond James and Associates 39th Annual Institutional Investors Conference | 22 70 80 90 100 110 120 130 140
2017 2018E 2019E 2020E 2021E
Oil Production MB/d
400 800 1,200 1,600 2,000 2017 2018E 2019E 2020E 2021E
EBITDAX $MM
Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes lease operating costs are equal to 2017 levels for the mid-point of the range of planning scenario outcomes. Ranges of portfolio planning scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. All discretionary cash flow reinvested in business for each scenario. * See www.crc.com Investor Relations for a description of the calculation of debt-adjusted per share and other important information.
Combined with mid-cycle commodity prices, we are positioned for growth in:
Portfolio Planning Scenarios Portfolio Planning Scenarios
Capital focused on oil projects that provide Increa easi sing Margin ins Low w Decline line Rates es Compoun
ding Cash sh Flow
Estimated Range of EBITDAX Outcomes
300 600 900 1,200 1,500
2017 2018E 2019E 2020E 2021E
Capital ($MM)
Estimated Ranges of Capital Investments
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Grow within cash flow Industry leading decline rate Integrated and complementary infrastructure
Maintain Production Production and Cash Flow Growth
Production Innovation Deep Inventory
Investment Case for CRC
World-class assets with significant inventory Resilient model that preserves optionality and protects downside Focused on value and poised for growth
Moved from defense to offense
Competitive Advantages
Disciplined portfolio management Potential for EBITDAX growth
500 1,000 1,500 2,000 2,500 2017 2018E 2019E 2020E 2021E
$MM Clear runway and available cash
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CRC Focus
Culture Regulatory Engagement Employee Engagement
Silo / Separate Reactive Low One CRC Proactive High
Financial Priorities
$
Net Debt Capital Efficiency Annual Production Costs
$7BN Low $1.2BN $4BN High $750MM
Portfolio Management
Maintenance Capital Product Focus Actionable Inventory
High Rate Low Low Value High
Strategic Flexibility
Capital Flexibility Production Growth Trajectory Price Outlook
Preservation Decline Trough Acceleration Growth Peak
$
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$3.26 $3.14 $2.95 $3.00 $2.75 $2.42 $3.09 $2.90 $2.47 $2.56 $2.77 $2.66 $2.28 $2.67
0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50
1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017
$/Mcf
NYMEX Realizations
66% 62% 72% 79% 40% 52% 70% 63% 59% 66% 72% 37% 50% 65% 0% 20% 40% 60% 80% 100% 1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017 % of WTI & Brent WTI Brent $51.91 $48.29 $48.21 $55.40 $48.80 $43.32 $50.95 $50.24 $47.98 $50.02 $56.92 $49.19 $42.01 $51.24 $54.66 $50.92 $52.18 $61.54 $53.64 $45.04 $54.82 30 40 50 60 70 1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017 $/Bbl WTI Realizations Brent Realization %
97% 99% 104% 103% 101% 99% 101% Realization %
89 % 79% 87% 92% 97% 94% 86%
Oil il Pric ice Realizati lization n (wit ith h Hedges) ges) Gas Pric ice Realizati lization NGL Price e Realization ation - % of W WTI & B Brent
CRC believes near-term differentials will remain strong
and reduction in heavy waterborne crude has positively influenced differentials.
markets.
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1 Defined as indebtedness outstanding under 2014 Credit Facility to LTM Consolidated EBTIDAX.
Note: The full amendment was filed with Form 8K on November 13, 2017.
Descri cript ption ion
Revolv volver er Commit itmen ent
2017 Term Loan n Indeb ebtedn ednes ess
2014 Revolver Maturit rity Extensio ion
Non-Bor
ing Base Asset et Sale e Proceeds eeds
par and subject to the following: – 25% of the proceeds up to $500 million (excluding the Elk Hills Power Plant) shall be applied to repay drawings under the 2014 Revolver – 50% of the proceeds in excess of $500 million and less than $1 billion (excluding the Elk Hills Power Plant) shall be applied to repay drawings under the 2014 Revolver – 75% of the proceeds in excess of $1 billion (excluding the Elk Hills Power Plant) shall be applied to repay the 2014 Revolver and reduce commitments by a corresponding amount – 50% of the proceeds of the Elk Hills Power Plant shall be applied to repay drawings under the 2014 Revolver Financ ancial ial Coven venants nts
– 2017-2019: ≤ 1.90x – 2020-2021: ≤ 1.50x
Other r Terms
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Summary of Deal Partner
▪ Affiliate of Ares Management (Ares)
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
▪ 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
Exit Provisions
▪ 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
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California Resources Elk Hills, LLC Elk Hills Power, LLC
Contributed Assets $750 MM gross proceeds Class A (50%) and Class C (95.25%) Common Interests Power and Gas Processing Services Commercial Agreement Capacity Charges
Ares Management, L.P.
$750 MM gross proceeds Class B Preferred Interests, Class A and Class C Common Interests
deleveraging through cash flow growth
control
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2014 Revolving Credit Facility Capacity - $1 billion
2017 Term Loan - $1.3 billion 2016 Term Loan - $1 billion 2015 Second Lien - $2.25 billion Unsecured Notes - $0.393 billion
Drawn Revolver $837 $0 $250 $500 $750 $1,000
3Q17 PF 4Q17* ($MM)
Revolver Availability $431 Revolver Availability $850 Cash $11 Cash $441 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400
3Q17 PF 4Q17* Availability ($MM)
Increased eased Liqui uidity** dity**
* Pro Forma for the Ares JV and $50mm private placement ** Subject to minimum liquidity requirement under 2014 Revolving Credit Facility. Includes unrestricted cash.
Reduc uced ed Revo volver er Borro rowing ng Added in November Debt Hierarchy
Undr drawn Revolv volver er
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6,7651 4,502 3,000 4,000 5,000 6,000 7,000
2Q15 Debt Exchange for 2L Open Market Repurchases Equity for Debt Exchange Cash Tender for Unsecureds Cash Flow Ares Transactions PF 4Q17
Total Net Debt ($ MM)
2
Cumulative Net Debt Reduction Total
Total Net Principal Reduction $535 million $153 million $102 million $625 million $59 million $789 million $2,263 million
1 Represents mid-second quarter 2015 peak debt. 2 Includes operating cash flow, positive working capital and proceeds from asset sales in 1H 2017, net of restricted cash. 3 Pro Forma net debt at 4Q17 includes the payoff of the 12/31/2017 outstanding balance of $363 million on our RCF and $441 million of available cash after the completion of the Ares transactions.
Continue to seek opportunistic transactions that reduce overall debt.
3
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1Q 2018 2Q 2018 3Q 2018 4Q 2018 1Q 2019 Sold Calls Barrels per Day 9,000 6,200 16,100 16,100 1,100 Weighted Average Ceiling Price per Barrel $59.58 $60.24 $58.91 $58.91 $60.00 Purchased Calls Barrels per Day
Weighted Average Ceiling Price per Barrel
Purchased Puts Barrels per Day 1,200 1,200 6,100 1,100 14,100 Weighted Average Floor Price per Barrel $45.82 $45.83 $61.48 $45.85 $58.93 Sold Puts Barrels per Day 29,000 29,000 24,000 19,000 10,000 Weighted Average Floor Price per Barrel $45.00 $45.00 $46.04 $45.00 $47.50 Swaps Barrels per Day 38,300 34,000 19,000 19,000 7,000 Weighted Average Price per Barrel $60.03 $60.00 $60.13 $60.13 $67.71 Percentage of 4Q 2017 Oil Production Hedged* 49% 49% 44% 31% 25% 25% 26% 26%
Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and $70 Brent. For potential volume changes and further details please see Attachment 10 of our Earnings Release. * Assumes counterparty options are not exercised.
We target hedges
Strategy
Protect cash flow for capital investments and covenant compliance
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0% 10% 20% 30% 40% Year 1 Year 2 Year 3 Year 4 Year 5
Normalized Decline Rates
2010 Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells Source: Data from Wood Mackenzie, CRC analysis
Recent wells in the onshore Lower 48 are showing steeper declines
2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 2009 2010 2011 2012 2013 2014 2015 2016
Production (BOPD)
Pre 2010 2010 Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells
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0% 10% 20% 30% 40% 50%
1 Year Decline
Median: 29%
0% 10% 20% 30% 40% 50% 60% 70% 80%
3 Year Decline
Median: 49%
CRC CRC
Peers included: CLR, COG, CPE, CXO, DNR, EGN, EOG, EPE, FANG, HK, LPI, MRO, MTDR, MUR, NFX, OAS, PDCE, PE, PXD, QEP,RRC, RSPP, SM, SN, WLL,WPX, and XEC. Source: Wood Mackenzie - Operated Production Data through 2016, CRC analysis. FY 2016 Production Percentage Liquids Less than 55% 55% - 75% Greater than 75%
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(2,500) (2,000) (1,500) (1,000) (500)
1,000 1,500
Unlevered Free Cash Flow ($MM)
CRC
Peers included: APA, APC, AR, BBG, CHK, CLR, COG, CPE, CRK, CRZO, CXO, DNR, DVN, ECR, EGN, EOG, EPE, EQT, FANG, GPOR, GST, HK, JONE, LPI, MRO, MTDR, MUR, NBL, NFX, OAS, PDCE, PE, PXD, QEP, REI, RICE, RRC, RSPP, SD, SGY, SM, SN, SWN, UNT, UPL, VNR, WLL, WPX, and XEC. Source: FactSet.
2016 Unlevered Free Cash Flow
Average: $(293.5)MM
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Highlights:
― Initial commitment of $160MM
100% of project capital for 90% WI, with CRC carried on its 10% WI ― CRC interest reverts to 75% after target IRR is achieved ― CRC retains early termination options
Basin ― Kern Front, Mt. Poso, Pleito Ranch, Wheeler Ridge
Highlights:
― Two tranches of $50MM ― Total of $100MM funded
capital in exchange for a net profits interest (NPI) ― Investor NPI interest reverts to CRC after low teens target IRR ― CRC retains early termination
Basin
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2,000.00 3,000.00 4,000.00 5,000.00 6,000.00 7,000.00 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100103106109112115118 JV Share Typical E&P Share
deals, a typical deal structure is
Interest
hurdle rate is achieved:
Hurdle Rate Reached
Production Time
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200 400 600 800
BOEPD
YEAR 5 200 400 600 800
BOEPD
YEAR 5
Gas
200 400 600 800
BOEPD
YEAR 5
0% 25% 50% 75% 100%
Portfolio Mix Higher Oil to Gas Price Ratio Lower Oil to Gas Price Ratio
Gas Unconventional Primary Waterflood Steamflood Workover
EUR (MBOE per $10MM) 1,385 1,265 1,060 % Oil 81% 70% 53% Development Cost/BOE $7.20 $7.90 $9.40 Recycle Ratio 3.4x 2.9x 2.2x
For illustration of portfolio optionality based on normalized results per $10MM of investment and not guidance. See endnote for details on type curves. Prices for recycle ratio are $65 Brent and $3.50 NYMEX.
Oil Gas Oil Oil Gas
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0. 0.0 1. 1.0 2.0 2.0 3. 3.0 4. 4.0
VCI
Kern Front Buena Vista Bardsdale Asphalto Grimes Lost Hills Elk Hills Buena Vista Nose Buena Vista Kettleman McDonald Anticline Huntington Beach Elk Hills Elk Hills Rio Vista McKittrick Kettleman Kettleman Gunslinger Tompkins Hill Midway Sunset Mount Poso Montalvo Kettleman Willows North Antelope Hills Paloma Paloma North Shafter Oxnard Rincon Pleito Ranch Railroad Gap South Mountain Rio Viejo Rose San Miguelito South Mountain Wilmington Saticoy Wheeler Ridge Yowlumne
Steamfloods Primary Waterfloods Shales Gas
All economics are pre-tax. VCI range by project is summarized from ‘Type Wells by Mechanism’ in subsequent slides. Low end of range assumes $55 Brent and high end assumes $75 Brent and $3.50 NYMEX.
1.3 VCI implies $1.30 of PV-10 for every $1 invested
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25 50 75 100 1 2 3 4 BOPD YEAR
* Information is for a steamflood pattern assuming 3 producers per 1 injector and is fully burdened with new steam generator infrastructure costs of $900K per pattern. At low prices, new steam generation infrastructure is not added to the project. See endnotes for important information about our type curves.
PARAMETERS PER PATTERN Operating Expense/bbl
$10-20
Capital Cost *
$2.8MM
Total EUR (MBO)
270
Peak Rate (BOPD)
90
D&C (days)
15
Royalty
10%
Composite Type Curve Kern Front Actuals
CRC OPERATED FIELDS
Oxnard Midway Sunset McKittrick McDonald Anticline Kern Front Lost Hills
Hills
CRC STEAMFLOODS
300 Near Term Growth Plan Pattern Locations
$NYMEX
VCI
$3.5 $3 $2.5 $50 1.0 1.1 1.2 $55 1.3 1.4 1.5
$ BRENT
$60 1.6 1.7 1.8
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15 30 45 60 1 2 3 4 BOEPD YEAR
* Capital cost is fully burdened with facilities, injectors and tie-ins. Assumes 5-spot pattern with a 1:1 producer to injector ratio.
VCI
165 190
EUR
215 $50 1.3 1.5 1.7 $55 1.6 1.9 2.1
$ BRENT
$60 1.9 2.2 2.5
Composite Type Curve
Mount Poso Actuals Buena Vista Actuals
CRC OPERATED FIELDS
Rincon Saticoy South Mountain Paloma Mount Poso Kettleman Buena Vista Elk Hills
CRC NEW & POTENTIAL WATERFLOODS
See endnote for important information about our type curves.
350 Near Term Growth Plan Locations
PARAMETERS PER PATTERN Operating Expense
$19/BOE
Capital Cost*
$1.2MM
Total EUR (MBOE)
190
Peak Rate (BOEPD)
35
Drilling Time (days)
10
Royalty
12.5%
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40 80 120 160 1 2 3 4 BOEPD YEAR
* Capital cost is fully burdened with facilities, injectors and tie-ins. ** A majority of locations are subject to PSCs, which have a 49% NPI. For NPV calculation, this can be modeled as 49% WI/NRI. For Production Rate, Net/Gross ratio is typically 75% when including cost recovery barrels. See endnote for important information about our type curves.
PARAMETERS Operating Expense
$19/BOE
Capital Cost*
$1.8MM
Total EUR (MBOE)
165
Peak Rate (BOEPD)
120
Drilling Time (days)
14
Royalty
PSC**
VCI
140 165
EUR
190 $50 1.1 1.3 1.5 $55 1.4 1.6 1.9
$ BRENT
$60 1.6 1.9 2.2
Huntington Beach Actuals Elk Hills Actuals Composite Type well West Wilmington Actuals East Wilmington Actuals
CRC OPERATED FIELDS
San Miguelito Elk Hills Wilmington Huntington Beach
CRC REDEVELOPMENT WATERFLOODS
350 Near Term Growth Plan Locations
Raymond James and Associates 39th Annual Institutional Investors Conference | 43 PARAMETERS Operating Expense
$10/BOE
Capital Cost*
$5.0MM
Total EUR (MBOE)
430
Peak Rate (BOEPD)
360
Drilling Time (days)
30
Royalty
12%
* Capital cost includes drilling, completion, and tie-ins. Does not include 450 shallow (<5,000 ft) locations with costs under $1.5 MM/well and with similar economics.
VCI
400 430
EUR
460 $50 1.5 1.6 1.7 $55 1.7 1.8 2.0
$ BRENT
$60 1.9 2.1 2.2
150 300 450 600 750 900 1 2 3 4 BOEPD YEAR
Composite Type well Wheeler Ridge Actuals Bardsdale Actuals Pleito Ranch Actuals BV Nose Actuals
CRC OPERATED FIELDS
Montalvo Kettleman Saticoy Bardsdale South Mountain Elk Hills BV Nose Yowlumne Pleito Ranch Wheeler Ridge Paloma Rio Viejo
CRC PRIMARY
See endnote for important information about our type curves.
150 Near Term Growth Plan Locations
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Asphalto Elk Hills Buena Vista Kettleman Rose
Gunslinger Railroad Gap
CRC SHALE
200 300 400 500
1 2 3 4
BOEPD
New Pool Type Curve Infill Shale Curve
YEAR
Gunslinger Actuals Rose/N. Shafter Actuals Elk Hills Actuals Elk Hills (2001-2003) VCI
Infill New Pool $50 1.2 1.7 $55 1.3 1.9
$ BRENT
$60 1.4 2.0
*Capital cost includes drilling, completion and tie-ins. See endnote for important information about our type curves.
New Pool Operating Expense
$10/BOE $8/BOE
Capital Cost*
$5.0MM $2.5MM
Total EUR (MBOE)
765 220
Peak Rate (BOEPD)
500 143
Drilling Time (days)
30 20
Average Royalty
13% 13%
Infill
50 Near Term Growth Plan Locations (Split Evenly)
CRC OPERATED FIELDS
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delivered nearly 3 gallons of treated water to agriculture
2017, almost a 10% increase since 2015
In 2017, CRC supplied 4.9 billion gallons – over 15,000 acre-feet – of treated, reclaimed water for irrigation or recharge.
WA WATER ER MANAGE GED IN CRC’s OPERATIONS
Produced Water Fresh Water Non-Fresh Water
CRC set a new company record for water deliveries to agriculture in 2017, an 85% increase since 2015, preserving farmland and jobs. CRC’s operations in Long Beach use recycled or non-fresh water for 99.5% of their total water use.
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1 Current CRC estimate of reserves value as of December 31, 2017. Includes field-level operating expenses and G&A. Assumes
$3.00/MMBTU NYMEX.
2Reflects 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 December 31, 2017 debt at par and market cap as of February 19, 2018.
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 the investments, each using a 10% discount rate