third quarter 2015 earnings review - california resources … · 2015. 11. 5. · sn, tplm, wti,...

Third Quarter 2015

Earnings ReviewTodd Stevens| President & CEO

Mark Smith | Sr. EVP & CFO | Los Angeles, CA| November 5, 2015

3Q15 Earnings

Forward-Looking / Cautionary StatementsThis 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

3Q15 Earnings

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

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

Portfolio of Lower-Risk, High-Growth Opportunities

• Oil weighted reserves

• Broad exploration and development program

• 30%-100%+ rates of return on select individual projects

Shareholder Value Focus

• Internally funded capital expenditure program

• Optimized capital allocation

• Unlocking under-exploited resource potential utilizing modern technology

3Q15 Earnings4

Management Priorities and Response

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

Narrowed discussions with leading counter-

parties 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

Priorities Execution

3Q15 Earnings5

631

180

0

100

200

300

400

500

600

700

3Q14 Volume Price Costs Interest Tax Working

Capital and

Other

3Q15

$ M

M

Op

era

tin

g C

ash

Flo

wCRC Executing on Controllables

3Q15 Earnings6

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.

3Q15 Earnings7

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).

PV10 pre-tax cash flows

PV10 of investmentsVCI =

Value Creation Index

Measures value created per dollar investment (“Bang for the buck”)

3Q15 Earnings8

• 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

Flexible High Return Inventory

Pace – Rigs/Year 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

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

55 Strip** 65 75

Dri

llin

g C

apit

al (

$B

n)

Actionable Inventory at Various Price Levels

Workover

Waterflood

Unconventional

Steamflood

Primary

3Q15 Earnings

Progressing Inventory to VCI Threshold

9

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

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

Recovery Mechanism

Prod Drill

Count

Inj Drill


Prod Drill

Count

Inj Drill

Count

WO

Count

Net Capex

$MM




Grand Total 583 32 322 869 Grand Total 254 29 319 370

Recovery Mechanism

Prod Drill

Count

Inj Drill


Prod Drill

Count

Inj Drill

Count

WO

Count

Net Capex

$MM




Grand Total 875 40 353 1,223 Grand Total 319 29 322 530

@ $50 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $50 Oil, $3.00 Gas ($3.50 Gas for >= 2017)



3Q15 Earnings

Primary$409%

Exploration$153%

Waterfloods$17540%

Steamfloods$15535%

Unconventional$358%

Other$205%

Focus on steamflood and waterflood

projects, which provide:

Attractive returns at current prices

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

2015 Capital Budget ($MM)– By Drive

Drilling$150 34%

Workover$50 11%

Development Facilities

$130 30%

Exploration$15 3%

Other$95 22%

2015 Total Capital Budget

Total: $440 million

1Other includes seismic, maintenance and other investments.

1

Targeting Higher-Margin, Higher Return, Low Decline Crude Oil Projects

10

3Q15 Earnings11

• We have assessed 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

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

• 2.3 Million Acres

• ~60% of Land held in Fee

• Large Economic Development

Project Inventory

• Seismic

• Robust Exploration Portfolio

3Q15 Earnings12

Living Within Cash Flow

0

50

100

150

200

250

300

1Q15 2Q15 3Q15

$ M

M

Adj. EBITDAX* Operating Cash Flow Capital Investment

* See Appendix for reconciliations to GAAP

3Q15 Earnings13

Defending Margins Through Efficiencies and

Focus on Cash Costs

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.

$4.97 $5.00 $5.28 $5.57 $5.09 $5.13 $4.61

$3.74 $3.88 $3.79 $3.55 $3.65 $3.63 $2.89

$19.00 $19.03 $18.35 $16.65 $16.20 $16.59 $16.91

$2.23 $1.06 $1.69 $4.49$1.11 $0.52 $0.34

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15E

Cash Costs $/Boe

Adj G&A* Taxes (non income) Production Costs Exploration Guidance

2014 Average = $29.572015E Average = $25.51

* Adjusted G&A expenses exclude early retirement and severance costs which amounted to $10 million in 2Q15 and $62 million in 3Q15.

3Q15 Earnings

Focus on Oil Enhances Base & Margins

1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15E FY 2014 FY 2015E

Production By Stream (MBoe/d)

Oil NGL Gas Guidance

Average Total Production

159 Mboe/d

Average Oil Production

99 MBbl/d

14

3Q15 Earnings

3Q15 Results Summary Comparison

15

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

3Q15 Earnings

$95.12 $94.21 $97.97 $93.00

$51.00

$103.80 $104.02 $104.16

$92.30

$50.28

$110.90 $111.70 $108.76

$99.51

$56.61

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2011 2012 2013 2014 YTD 3Q15

$/B

bl

WTI Realizations Brent

$4.11

$2.81

$3.66

$4.39

$2.86

$4.31

$2.94

$3.73

$4.34

$2.72

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 YTD 3Q15

$/M

cf

NYMEX Realizations

NGL Price Realization - % of WTI

Realization % of WTI

109% 110% 106 % 99% 97% Realization % of NYMEX

105% 105 % 102 % 101% 92%

Oil Price Realization* Gas Price Realization

• Several discrete events in California in 1H

contributed to widening differentials

• Realizations have gradually improved since

Q1

74%

56%51% 51%

39%

0%

10%

20%

30%

40%

50%

60%

70%

80%

2011 2012 2013 2014 YTD 3Q15

% o

f W

TICRC – Price Realizations

16

* Reflects realizations with hedges

3Q15 Earnings

160,000158,000

+3,000 -4,000

-1,000

140,000

145,000

150,000

155,000

160,000

165,000

3Q14 Oil Gas NGL 3Q15

Boe/d

Strong Oil Volumes Drive Quarterly Production

17

3Q15 Earnings

Cost Variance

18

3Q14 2Q15 3Q15

Production costs($/Boe)

$18.35 $16.59 $16.91

Taxes other than on income ($MM)

$56 $53 $42

Exploration expense ($MM)

$25 $7 $5

Interest expense($MM)

NA $83 $82

3Q15 Earnings

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

3Q15 Earnings20

Opportunistically Built Hedge Portfolio

• 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

2015/2016 Crude Oil Brent Hedges*

$40

$45

$50

$55

$60

$65

$70

$75

$80

Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016

40,000 Bbl/d $73.88 call

40,000 Bbl/d $61.25 put

35,500 Bbl/d $66.15 call

30,500 Bbl/d $52.38 put

3,000 Bbl/d $74.42 call

3,000 Bbl/d $50.00 put

1,000 Bbl/d $61.25 swap

3Q15 Earnings

• 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

Capitalization as of 9/30/15 ($MM)

$25

$625

$1,000

$1,750

$2,250

$0

$500

$1,000

$1,500

$2,000

$2,500

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

Term Loan

Debt Maturities ($MM)

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.

Focus on Balance Sheet

21

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-103 / 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

3Q15 Earnings

• 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

Approved Credit Facility Amendment Provides Additional

Financial Flexibility

Consolidated leverage ratio Consolidated interest expense ratio

22

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

3Q15 Earnings

4Q15 Guidance

23

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%

3Q15 Earnings

NY00813G / 589203_1.WOR

Sacramento Basin

19 MMBoe Proved Reserves

7 MBoe/d production

San Joaquin Basin


111 MBoe/d production

Ventura Basin



Los Angeles Basin



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

Focused and Experienced Management Team:

Proactive executive team that swiftly executes strategic objectives

Poised to Take Advantage of a Commodity Price Recovery

24

Reserves as of 12/31/14; Production figures reflect average YTD 2015 rates.

3Q15 Earnings25

California Resources Corporation

Appendix

3Q15 Earnings

Non-GAAP Reconciliation for Adjusted EBITDAXFor the

Third QuarterEnded September 30,

For the NineMonths EndedSeptember 30,

FullYear

($ 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

3Q15 Earnings

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 annatural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cashflows 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 construedas 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 anasset 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

3Q15 Earnings

Non-GAAP Reconciliation for Adjusted EPS

28

For the Third Quarter

Ended September 30,

For the Second Quarter Ended

June 30,

For the NineMonths EndedSeptember 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.

3Q15 Earnings

• Measures value created per dollar investment (“Bang for the buck”)

• Corporate Target 1.3

PV10 pre-tax cash flows

PV10 of investmentsVCI =

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

Value Creation Index

third quarter 2015 earnings review - california resources … · 2015. 11. 5. · sn, tplm, wti,...

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