first quarter 2016 earnings review · 1q16 earnings opportunistically built hedge portfolio* * as...
TRANSCRIPT
First Quarter 2016
Earnings ReviewTodd Stevens| President & CEO| Los Angeles, CA| May 5, 2016
Mark Smith | Sr. EVP & CFO
1Q16 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 and workoverprogram, production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency of our operating cash flow to fund planned capital expenditures; faster than expected production decline rates; inability to implement our capital investment program; inability to replace reserves; inability to obtain government permits and approvals; inability 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; risks related to our disposition and acquisition activities; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; 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; effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the Spin-off and the agreements related thereto. Material risks are further discussed in “Risk Factors” in our Annual Report on Form 10-K and subsequent 10Qs available on our website at crc.com. Words such as "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and CRC undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.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, adjusted EPS 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, adjusted EPS and PV-10 to the nearest comparable measure in accordance with GAAP, please see the Appendix.
2
1Q16 Earnings
Diverse Resource Base
• Interests in 4 of the 12 largest fields in the lower 48 states
• 644 MMBoe proved reserves (12/31/2015)
• 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
• Operations exclusively in California
• Assembled largest privately-held land position in California
• Operator of choice in sensitive environments
Portfolio of Lower-Risk, Lower-Decline Opportunities
• Oil weighted reserves
• Broad exploration and development program
Shareholder Value Focus
• Internally funded capital investment program
• Optimized capital allocation
3
1Q16 Earnings
Management Priorities and Response
1. Address Balance Sheet
2. Adjust Activity Levels for Current
Environment
• Live within means and align
capital investments with
projected cash flow
3. Focus on base production and
protect our margins
4. Right-size costs for the current
operating environment
Reduced outstanding debt with free cash
flow and through open market repurchases
No change to borrowing base in the spring
redetermination
Generated free cash flow after working
capital of $87 million
Production exceeded the midpoint of
guidance at 148 Mboe/d and was
accomplished with no drilling capital
Delivered the same amount of operating
cash flow after working capital in 1Q16
versus 1Q15 despite a 36% lower average
crude oil price
Focused on costs: Achieved 24% reduction
in production costs year-over-year
Successfully concluded the Elk Hills power
plant turnaround on budget and ahead of
schedule
Priorities Execution
4
1Q16 Earnings
Living Within Cash Flow
-$5
$5
$15
$25
$35
$45
$55
$65
$75
-25
25
75
125
175
225
275
1Q15 2Q15* 3Q15 4Q15* 1Q16
Bre
nt
Pri
ce
$ M
M
Adj. EBITDAX** Operating Cash Flow Capital Investment Brent Price
* Operating cash flow includes a semi-annual cash property tax payment** See Appendix for reconciliations to GAAP
5
1Q16 Earnings
• We have assessed various deleveraging alternatives and are
taking strategic steps to delever the balance sheet
Deleveraging Options
UPSTREAM
• JV
• M&A
MIDSTREAM
• MLP
• Drop into Existing MLP
• Sale
• Triple Net Lease
CAPITAL MARKETS
• Debt Exchange
• Open market bond
repurchases
AVAILABLE ASSETS
• 14 Gas Plants with 650 MMcfd Capacity
• Elk Hills has largest Gas Plant Complex in CA
• 300 Compressors / Stations with 395,000 HP
of Compression
• 600 MW Electrical Generation with 700 miles
of High Voltage Transmission Lines
• 305 Tank Settings / LACT / Sales Facilities
• 74 Water Plants / Treatment Facilities
• 50 Steam Generators with 220,000 Bbl Steam
Capacity
• ~20,000 Miles of Pipelines
AVAILABLE ASSETS
• 2.4 Million Acres
• ~60% of Land held in Fee
• Large Economic Development
Project Inventory
• Seismic
• Robust Exploration Portfolio
TRANSACTION
• Exchange offer for Unsecured
Notes reduced debt by $563
million
• Repurchased ~$135mm in
principal amount of unsecured
bonds for $25mm in 4Q15 and
1Q16
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1Q16 Earnings
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) and
longer term value / future growth (steamfloods/waterfloods).
PV10 pre-tax cash flows
PV10 of investmentsVCI =
Value Creation Index
Measures value created per dollar investment (“Bang for the buck”)
7
1Q16 Earnings
Strong Execution Track Record
130
135
140
145
150
155
160
165
170
1Q15 2Q15 3Q15 4Q15 1Q16
Mb
oe
/d
Total ProductionGuidance vs. Actual
Production Guidance Range Actual
0
40
80
120
160
1Q15 2Q15 3Q15 4Q15 1Q16
$M
M
Capital InvestmentGuidance vs. Actual
Capital Investment Guidance Range Capex Actual
Production will drop with natural decline; capital focused on mechanical integrity and safety
8
1Q16 Earnings
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
1Q 15 2Q 15 3Q 15 4Q 15 1Q 16
Pro
du
ctio
n C
ost
s ($
/Bo
e)
Steam Injectant Gas Plant Expense
Energy Supports and Other
Downhole Maintenance Workovers/Well Enhancement
Surface Operations and Maintenance Pipeline/Transportation/Terminals
9
Defending Margins By Managing Costs
~15%
Decrease
1Q16 Earnings
Capitalization as of 3/31/16 ($MM)
$25
$625$392
$805
$2,250
855
$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)*
Focus on Balance Sheet
• Deleveraging is a priority
• Utilized free cash flow to execute open
market purchases of bonds and make
payment on term loan
• Borrowing base reconfirmed at $2.3 billion
1 Effective May 2, 2016 the borrowing base under our Credit Facilities was $2.3 billion. As of March 31, we had the ability to incur total borrowings under the RCF of $1.3 billion less outstanding amounts (or approximately ~$578MM).
2 PV-10 as of 12/31/15 based on SEC five-year rule applied to PUDs using SEC price deck. See Appendix for reconciliation to GAAP.
1st Lien Secured RCF1 695
1st Lien Secured Term Loan 975
Senior 2nd Lien Notes 2,250
Senior Unsecured Notes 2,052
Total Debt 5,972
Less cash (10)
Total Net Debt 5,962
Equity (952)
Total Net Capitalization 5,010
Total Net Debt / Net Capitalization 119%
Total Net Debt / LTM Adjusted EBITDAX 7.2x
LTM Adjusted EBITDAX / Interest Expense 2.6x
PV-102 / Total Net Debt 0.8x
Total Net Debt / Proved Reserves ($/Boe) $9.26
Total Net Debt / PD Reserves ($/Boe) $12.40
Total Net Debt / Production ($/Boepd) $40,284
* As of 3/31/16
10
1Q16 Earnings
$94
$55$64
$51
$45
$35
0
10
20
30
40
50
60
70
80
90
100
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
10/1/14 3/31/15 6/30/15 9/30/15 12/31/15 3/31/16
Bre
nt
Oil
($/B
bl)
Tota
l Deb
t ($
M)
Total Debt
Long Term Notes Term Loan Revolving Credit Facility Oil Price
CRC Effectively Managing Down Debt
11
Reduced debt approximately $700 million from the high point in 2Q15 through free
cash flow, debt exchanges and open market repurchases of bonds
1Q16 Earnings
Progressing Inventory to VCI Threshold
12
0
1,000
2,000
3,000
4,000
5,000
6,000
$40 $50 $60
Dri
llin
g an
d W
ork
ove
rIn
ven
tory
($
MM
)
Brent Marker Price ($/Bbl)
Economic Project Inventory
VCI 1.3 VCI 1.0
1Q16 Earnings
Capex Reduction
• 2016 Capital Investment Plan to focus on mechanical integrity and safe
operations
• Monitor cash flow throughout the year and retain flexibility to increase
investments in drilling and capital workovers to the extent crude oil prices show
sustained improvement, while abiding by financial covenants
* Full Year 2016 Guidance
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
RIGS 3.3 3 3 2.3 0 0 0 0
Quarterly
Operations
CAPEX,
$mm
FY 2016E2015 Actual
$133 $95 $95 $78 $50*
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1Q16 Earnings
Opportunistically Built Hedge Portfolio*
* As of April 28, 2016
• Hedge book started at zero post spin; we target hedges on 50% of production
• Strategy focuses on protecting cash flow for capital investments and covenant compliance
Q2 2016 Q3 2016 Q4 2016 2017 2018
Calls
Barrels per Day 35,500 4,000 23,000 30,000 23,300
Wtd Avg Ceiling Price per Barrel $66.15 $71.13 $53.67 $55.68 $57.99
Puts
Barrels per Day 55,500 28,000 3,000 - -
Wtd Avg Floor Price per Barrel $50.14 $50.65 $50.00 - -
Swap
Barrels per Day - 1,000 25,000 - -
Wtd Avg Price per Barrel - $61.25 $49.10 - -
14
1Q16 Earnings
$97.97 $93.00
$48.80
$33.45
$104.16
$92.30
$49.19
$36.39
$108.76
$99.51
$53.64
$35.08
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$120
2013 2014 2015 1Q16
$/B
bl
WTI Realizations Brent
$3.66
$4.34
$2.75
$2.07
$3.73
$4.39
$2.66
$2.05
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
2013 2014 2015 1Q16
$/M
cf
NYMEX Realizations
NGL Price Realization - % of WTI
Realization % of WTI
106% 99% 97% 109% Realization % of NYMEX
102% 101 % 97% 99%
Oil Price Realization* Gas Price Realization*
• Oil pricing continued to deteriorate even further in 1Q 2016
• NGL pricing has followed the general energy market lower.
Downside pressure has come from extraction volumes as
gas production throughout the U.S. has continued to
increase
• Natural gas prices continued to decline due to continued
supply growth and lower demand which reflects Aliso
Canyon and mild weather
51% 51%
40%
49%
0%
10%
20%
30%
40%
50%
60%
2013 2014 2015 1Q16
% o
f W
TICRC – Price Realizations
* Reflects realizations with hedges
15
1Q16 Earnings
115 115
-40
-20
0
20
40
60
80
100
120
140
1Q15 Volume Price Costs Interest Working
Capital and
Other
1Q16
$ M
M
Op
era
tin
g C
ash
Flo
wCRC Executing on Controllable Items
16
1Q16 Earnings
Quarterly Cost Comparison
1Q15 4Q15 1Q16
Production costs($/Boe)
$16.20 $15.51 $13.69
Taxes other than on income ($MM)
$55 $30 $39
Exploration expense ($MM)
$17 $7 $5
Interest expense($MM)
$79 $82 $74
17
1Q16 Earnings
Managing Base Production with No Drilling Capital
4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16E FY 2014 FY 2015 FY 2016E
Mb
oe
/d
Production By Stream (MBoe/d)
Oil NGL Gas Guidance
159 Mboe/d
Average Oil
Production
Average Total
Production
160 Mboe/d
99 MBbl/d104 MBbl/d
18
1Q16 Earnings
1Q16 Results Summary Comparison
1Q15 4Q15 1Q16
Adjusted EPS* ($0.25) ($0.20) ($0.26)
Oil Production 108 MBbl/d 102 MBbl/d 98 MBbl/d
Total Production 166 MBoe/d 155 MBoe/d 148 MBoe/d
Realized Oil Price w/ Hedge ($/Bbl) $46.44 $45.88 $36.39
Realized NGL Price ($/Bbl) $21.55 $19.56 $16.39
Realized Natural Gas Price w/ Hedge($/Mcf) $2.84 $2.44 $2.05
Adjusted EBITDAX* $198 mm $226 mm $124 mm
Capital Investments $133 mm $78 mm $21 mm
Cash Flow from Operations $115 mm ($9 mm)** $115 mm
*See Appendix for reconciliations to GAAP**Operating cash flow includes a semi-annual cash property tax payment
19
1Q16 Earnings
2Q16 Guidance
Anticipated Realizations Against the Prevailing Index Prices for 2Q16
Oil 85% to 89% of Brent
NGLs 43% to 47% of Brent
Natural Gas 81% to 85% of NYMEX
Production, Capital and Income Statement Guidance
Production 138 to 143 MBOE per day
Capital $8 to $12 million
Production Costs $15.75 to $16.25 per BOE
G&A $4.15 to $4.45 per BOE
DD&A $11.10 to $11.30 per BOE
Taxes other than on income $38 to $42 million
Exploration expense $4 to $8 million
Interest expense $74 to $78 million
Cash Interest $130 to $134 million
Income tax expense rate 0%
Cash tax rate 0%
20
See Attachment 8 of the 1Q16 earnings press release issued May 5, 2016 for more details.
1Q16 Earnings
NY00813G / 589203_1.WOR
Sacramento Basin
14 MMBoe Proved Reserves
7 MBoe/d production
San Joaquin Basin
451 MMBoe Proved Reserves
110 MBoe/d production
Ventura Basin
47 MMBoe Proved Reserves
9 MBoe/d production
Los Angeles Basin
132 MMBoe Proved Reserves
34 MBoe/d production
World-Class Resource Base:
Large inventory of assets across basins and
drive mechanisms that provide strong
returns through the commodity price cycle
Exceptional Operating Leverage:
High level of operating leverage and control
favorably positions CRC to capitalize on a
strengthening commodity market
Stable Base:
Diverse and stable assets enable a predictable
production profile with low base declines
Focused and Experienced Management Team:
Proactive executive team that swiftly executes strategic objectives
Poised to Take Advantage of a Commodity Price Recovery
Reserves as of 12/31/15; Production figures reflect average FY 2015 rates.
21
1Q16 Earnings
California Resources Corporation
Appendix
22
1Q16 Earnings
Non-GAAP Reconciliation for Adjusted EBITDAXFor the
First QuarterEnded March 31,
($ in millions) 2016 2015
Net loss ($50) ($100)
Interest expense 74 79
Income taxes benefit (78) (69)
Depreciation, depletion and amortization 147 253
Exploration expense 5 17
Adjusted income items 13 5
Other (a) 13 13
Adjusted EBITDAX $124 $198
Net cash provided by operating activities $115 $115
Interest expense 74 79
Exploration expense 5 11
Changes in operating assets and liabilities (98) 1
Non-cash gains/(losses) in income 2 (26)
Adjusted income items 13 5
Other non-cash items 13 13
Adjusted EBITDAX $124 $198
(a) Includes non-cash items
23
1Q16 Earnings
Non-GAAP Reconciliation for PV-10
($ in millions)At December 31,
2015
PV-10 of Proved Reserves $5,059
Present value of future income taxes discounted at 10% (1,035)
Standardized Measure of Discounted Future Net Cash Flows
$4,024
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil andnatural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cashflows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construedas the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as anasset value measure to compare against our past reserves bases and the reserves bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity.
24
1Q16 Earnings
Non-GAAP Reconciliation for Adjusted EPSFor the
First QuarterEnded March 31,
($ in millions) 2016 2015
Net Loss $(50) $(100)
Non-cash loss on outstanding hedges 81 3
Severance costs and other employee-related costs 14 -
Plant turnaround costs 7 2
Gain on debt repurchases (89) -
Valuation allowance for deferred tax assets (a) (63) -
Tax effects of these items - (2)
Adjusted net loss $(100) $(97)
EPS – diluted $(0.13) ($0.26)
Adjusted EPS – diluted $(0.26) $(0.25)
Weighted average diluted shares outstanding 385.3 382.1
(a) Amount represents the out-of-period portion of the valuation allowance reversal.
25