Market Overview

California Resources Corporation Announces Second Quarter 2018 Results

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California Resources Corporation (NYSE:CRC), an independent
California-based oil and gas exploration and production company, today
reported a net loss attributable to common stock (CRC net loss) of $82
million, or $1.70 per diluted share, for the second quarter of 2018.
Adjusted net loss1 for the second quarter of 2018 was $14
million, or $0.29 per diluted share.

Quarterly Highlights Include:

  • Generated core adjusted EBITDAX1 of $337 million excluding
    the impact of $68 million of cash hedging losses and $24 million of
    stock-based compensation expenses
  • Reported adjusted EBITDAX1 of $245 million including these
    items, and an adjusted EBITDAX margin1 of 38%
  • Produced 134,000 BOE per day, above the midpoint of the guidance range
  • Internally funded capital investments of $170 million
  • Drilled 48 wells with internally funded capital and 35 wells with
    joint venture (JV) capital
  • Implemented $15 million of annualized synergies from the acquired Elk
    Hills interests, well ahead of anticipated pace

2018 Outlook:

  • Increased 2018 capital budget to a range of $650 million to $700
    million (including approximately $100 million or more of JV funding),
    subject to further adjustments based on commodity prices in the second
    half of the year and other developments
  • Incremental capital directed to drilling, workover and facilities
    projects in the San Joaquin, Los Angeles and Ventura basins
  • Third quarter 2018 production guidance of 134,000 to 138,000 BOE per
    day
  • Third quarter 2018 production forecast reflects CRC's return to a
    growth profile

Todd A. Stevens, CRC's President and Chief Executive Officer, said, "CRC
is building sustained momentum as our experienced and pressure-tested
teams continue to drive strong operational execution and as we take
advantage of the breadth and diversity of our California portfolio. Our
teams are driving improved efficiencies in the field and we expect to
deliver value-oriented production growth through the second half of
2018. This is showcased by our ability to capture near-term synergies
from the consolidation of CRC's flagship Elk Hills interests quicker
than expected, in addition to solid production results we are witnessing
from our drilling activity. Looking ahead, we are keenly monitoring
crude oil fundamentals and commodity markets to flex our capital plans
and enhance our 2019 cash flow performance. We expect our mid-cycle
capital investment plan should maximize value creation through
value-oriented production increases along with stronger EBITDAX growth
into 2019, particularly with the modified hedging strategy."

Second Quarter 2018 Results

For the second quarter of 2018, the CRC net loss was $82 million, or
$1.70 per diluted share, while adjusted net loss1 was $14
million, or $0.29 per diluted share. Adjusted net loss1
excluded $92 million of non-cash derivative losses and a net gain of $24
million on debt repurchases. These results compared to a net loss of $48
million, or $1.13 per diluted share, and an adjusted net loss of $78
million, or $1.83 per diluted share, in the prior year period. The 2018
results represented higher production and significantly higher realized
oil and NGL prices offset by hedge results and higher production costs
resulting from increased activity levels and equity compensation.

Total daily production volumes averaged 134,000 barrels of oil
equivalent (BOE) per day for the second quarter of 2018, compared to
129,000 BOE per day for the same period in 2017, an increase of nearly 4
percent driven by the Elk Hills acquisition. This net increase included
a 1,600 BOE per day negative effect on production volumes from our PSCs.
For the second quarter of 2018, oil volumes averaged 83,000 barrels per
day, NGL volumes averaged 16,000 barrels per day and gas volumes
averaged 210,000 thousand cubic feet (MCF) per day.

Realized crude oil prices, including the effect of settled hedges,
increased by $16.13 per barrel in the second quarter of 2018 to $64.11
per barrel from the prior year comparable period. Settled hedges
decreased realized crude oil prices by $9.08 per barrel. Average
realized NGL prices continued to be strong and registered $42.13 per
barrel, reflecting a realized price that was 56% of Brent prices.
Realized natural gas prices were $2.25 per MCF.

Production costs for the second quarter of 2018 were $231 million,
compared to $216 million in the second quarter of 2017, an increase of
$15 million primarily due to higher production from the Elk Hills
acquisition of $12 million, and increased equity compensation expense of
$5 million resulting from the stock price increase. On a per unit basis,
second quarter production costs were $18.93 per BOE, compared to $18.34
per BOE in the prior year comparable period. Second quarter unit
production costs were within the previously disclosed guidance levels,
and would have been $18.52 excluding higher equity compensation expense
or $0.56 per BOE lower on a sequential basis from first quarter 2018
unit production costs of $19.08. In line with industry practice for
companies operating under PSCs, CRC reports gross field operating costs
and only the Company's share of production volumes, which can result in
higher production costs per barrel. Excluding this PSC effect, per unit
production costs1 for the second quarter of 2018 would have
been $17.41. General and administrative (G&A) expenses were $90 million
for the second quarter of 2018, compared to $63 million in the first
quarter of 2018 and $31 million higher than the prior year comparable
period primarily related to higher equity compensation expense as a
result of CRC's increased stock price. CRC's increased stock price added
$19 million to the current year expense compared to the prior year
period. The Elk Hills acquisition added another $3 million to second
quarter 2018 G&A expense. The rest of the increase was mostly related to
the timing of certain expenses.

CRC reported taxes other than on income of $37 million, $6 million
higher than the prior year period largely due to higher property taxes
as a result of commodity price increases. Exploration expense of $6
million for the second quarter of 2018 remained flat to the prior year
comparable period.

Capital investment in the second quarter of 2018 totaled $170 million,
excluding JV capital. Approximately $115 million was directed to
drilling and capital workovers.

Cash provided by operating activities was $34 million, which included
interest payments of $154 million. CRC's working capital use is larger
in the second and fourth quarters of the year due to the timing of
interest and property tax payments. CRC's free cash flow1 was
$(136) million in the second quarter of 2018 after taking into account
capital that was funded by BSP.

Six-Month Results

For the first six months of 2018, CRC net loss was $84 million, or $1.81
per diluted share, compared to net income of $5 million, or $0.12 per
diluted share, for the same period of 2017. The 2018 results reflected
significantly higher realized oil and NGL prices offset by hedge results
and higher production costs resulting from higher activity levels,
energy costs and equity compensation. The adjusted net loss1
for the first six months of 2018 was $6 million, or $0.13 per diluted
share, compared with an adjusted net loss of $121 million, or $2.85 per
diluted share, for the same period of 2017. The 2018 adjusted net loss
excluded $99 million of non-cash derivative losses, a gain of $24
million on debt repurchases and a net $3 million charge related to other
unusual and infrequent items. The 2017 adjusted net loss excluded $110
million of non-cash derivative gains, $21 million of gains from asset
divestitures, a $4 million gain on debt repurchases and a $9 million
charge from other unusual and infrequent items.

Total daily production volumes averaged 129,000 BOE per day in the first
six months of 2018, compared with 131,000 BOE per day for the same
period in 2017, a decrease of 2 percent. This decrease included a
negative effect on production volumes from our PSCs of 2,000 BOE per
day. Excluding production from the Elk Hills acquisition and the effect
of PSC contracts, the decline from the first half of 2017 to the first
half of 2018 was 4%, which is below CRC's previously reported base
production decline range.

In the first six months of 2018, realized crude oil prices, including
the effect of settled hedges, increased $14.35 per barrel to $63.47 per
barrel from $49.12 per barrel for the same period in 2017. Settled
hedges reduced 2018 realized crude oil prices by $6.88 per barrel,
compared with an increase of $0.42 per barrel for the same period in
2017. Realized NGL prices increased 32 percent to $42.63 from $32.20 per
barrel in the first six months of 2017. Realized natural gas prices
decreased 6 percent to $2.51 per Mcf, compared with $2.68 per Mcf for
the same period in 2017.

Production costs for the first six months of 2018 were $443 million, or
$19.01 per BOE, compared to $427 million, or $18.02 per BOE, for the
same period in 2017. The Elk Hills transaction added $12 million to the
first six months' production costs, and the increase in equity
compensation expense added $6 million, or $0.25 per BOE. Excluding these
items, production costs were slightly lower in the current year period
compared to the prior year due to efficiencies delivered. Per unit
production costs, excluding the effect of PSC contracts, were $17.44 and
$16.92 per BOE for the first six months of 2018 and 2017, respectively.
G&A expenses for the first six months of 2018 were $153 million and for
the first six months of 2017 were $122 million, with the difference
almost entirely related to the increased equity compensation expense
resulting from the stock price increase.

Taxes other than on income of $75 million for the first six months of
2018 were $11 million higher than the same period of 2017 primarily due
to higher property taxes as a result of commodity price increases.
Exploration expense of $14 million for the first six months of 2018 was
$2 million higher than the same period of 2017.

Capital investment in the first six months of 2018 totaled $309 million
excluding JV capital, of which $209 million was directed to drilling and
capital workovers.

Cash provided by operating activities for the first six months of 2018
was $234 million and free cash flow was $(75) million after taking into
account capital that was funded by BSP.

Operational Update

CRC operated an average of ten rigs during the second quarter of 2018
and drilled 83 development wells with CRC and JV capital (51 steamflood,
18 waterflood, three primary and 11 unconventional). Steamfloods and
waterfloods have different production profiles and longer response times
than typical conventional wells and, as a result, the full production
contribution may not be experienced in the same year that the well is
drilled. In the San Joaquin basin, CRC operated seven rigs and produced
approximately 98,000 BOE per day for the second quarter of 2018. The Los
Angeles basin had three rigs directed toward waterflood projects, and
contributed 25,000 BOE per day of production in the second quarter.
Production for the Ventura basin was 6,000 BOE per day and the
Sacramento basin produced 5,000 BOE per day. Neither of these areas had
active drilling programs in the period.

2018 Capital Budget

With stronger expected cash flows from commodity price improvements and
increased production from the Elk Hills transaction, combined with
synergies resulting from the transaction, CRC increased its 2018 capital
program to a range from $650 million to $700 million, which includes
approximately $100 million or more of JV capital, subject to further
adjustments based on commodity prices in the second half of the year and
other developments. This is an increase from its previously stated range
of $550 million to $600 million. The incremental investment builds on
the momentum created to increase second half 2018 production with a more
substantial effect in 2019. The additional capital will primarily be
deployed to drilling, workovers and facilities in the San Joaquin, Los
Angeles and Ventura basins. As expected, CRC received funding of a third
tranche of the BSP capital in the second quarter of 2018.

Debt Reduction Update

CRC continued to validate its commitment to strengthening the balance
sheet. In the second quarter of 2018, CRC repurchased a total of $143
million in aggregate principal amount of the Company's outstanding debt
for $118 million in cash.

Borrowing Base Redetermination

As previously disclosed, effective May 1, 2018, CRC's borrowing base
under its 2014 Credit Agreement was reaffirmed at $2.3 billion.

Hedging Update

CRC continues to opportunistically seek hedging transactions to protect
its cash flow, operating margins and capital program while maintaining
adequate liquidity. For the first and second quarters of 2019, CRC has
hedged approximately 42,000 and 37,000 barrels per day, at approximately
$64 Brent and $67 Brent, respectively. In the third and fourth quarters
of 2019, the Company hedged approximately 32,000 and 22,000 barrels per
day, at approximately $71 and $73 Brent, respectively. A significant
majority of the 2019 hedges do not contain caps, thereby providing
upside to oil price movements. See Attachment 8 for more details.

CRC also purchased LIBOR interest rate caps in the second quarter of
2018 which cap the interest rate on a notional $1.3 billion at one-month
LIBOR of 2.75% through May 2021.

1 See Attachment 3 for explanations of how CRC calculates and
uses the non-GAAP measures of adjusted EBITDAX, core adjusted EBITDAX,
adjusted EBITDAX margin, free cash flow, production costs (excluding the
effects of PSC type contracts) and adjusted net income (loss), and for
reconciliations of the foregoing to their nearest GAAP measure as
applicable.

Conference Call Details

To participate in today's conference call scheduled for 5:00 P.M.
Eastern Daylight Time, either dial (877) 328-5505 (International calls
please dial +1 (412) 317-5421) or access via webcast at www.crc.com,
fifteen minutes prior to the scheduled start time to register.
Participants may also pre-register for the conference call at http://dpregister.com/10120726.
A digital replay of the conference call will be archived for
approximately 30 days and supplemental slides for the conference call
will be available online in the Investor Relations section of www.crc.com.

About California Resources Corporation

California Resources Corporation is the largest oil and natural gas
exploration and production company in California on a gross-operated
basis. The Company operates its world-class resource base exclusively
within the State of California, applying complementary and integrated
infrastructure to gather, process and market its production. Using
advanced technology, California Resources Corporation focuses on safely
and responsibly supplying affordable energy for California by
Californians.

Forward-Looking Statements

This presentation contains forward-looking statements that involve risks
and uncertainties that could materially affect CRC's expected results of
operations, liquidity, cash flows and business prospects. Such
statements include those regarding the Company's expectations as to
future:

  • financial position, liquidity, cash flows and results of operations
  • business prospects
  • transactions and projects
  • operating costs
  • operations and operational results including production, hedging,
    capital investment and expected value creation index (VCI)
  • capital budgets and maintenance capital requirements
  • reserves
  • type curves
  • expected synergies from acquisitions

Actual results may differ from anticipated results, sometimes
materially, and reported results should not be considered an indication
of future performance. While CRC believes the assumptions or bases
underlying its expectations are reasonable and makes them in good faith,
they almost always vary from actual results, sometimes materially.
Factors (but not necessarily all the factors) that could cause results
to differ include:

  • commodity price changes
  • debt limitations on its financial flexibility
  • insufficient cash flow to fund planned investment or changes to our
    capital plan
  • 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 its products
  • PSC effects on production and unit production costs
  • effect of stock price on costs associated with incentive compensation
  • competition with larger, better funded competitors for and costs of
    oilfield equipment, services, qualified personnel and acquisitions
  • incorrect estimates of reserves and related future net cash flows
  • joint venture and acquisition activities and our ability to achieve
    expected synergies
  • the recoverability of resources
  • 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
  • effects of hedging transactions and 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 CRC's Annual Report on Form
    10-K available on its website at www.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
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.

Attachment 1
SUMMARY OF RESULTS
  Second Quarter   Six Months
($ and shares in millions, except per share amounts)   2018       2017     2018       2017  
 

Statement of Operations Data:

Revenues and Other
Oil and gas sales $ 657 $ 439 $ 1,232 $ 926
Net derivative (loss) gain from commodity contracts (167 ) 43 (205 ) 116
Other revenue   59     34     131     64  
Total revenues and other (a)   549     516     1,158     1,106  
 
Costs and Other
Production costs 231 216 443 427
General and administrative expenses 90 59 153 122
Depreciation, depletion and amortization 125 138 244 278
Taxes other than on income 37 31 75 64
Exploration expense 6 6 14 12
Other expenses, net (a)   49     25     110     47  
Total costs and other   538     475     1,039     950  
 
Operating Income 11 41 119 156
 
Non-Operating (Loss) Income
Interest and debt expense, net (94 ) (83 ) (186 ) (167 )
Net gain on early extinguishment of debt 24 24 4
Gain on asset divestitures 1 1 21
Other non-operating expenses   (5 )   (5 )   (12 )   (9 )
 
(Loss) Income Before Income Taxes (63 ) (47 ) (54 ) 5
Income tax                
Net (Loss) Income (63 ) (47 ) (54 ) 5
Net income attributable to noncontrolling interests   (19 )   (1 )   (30 )    
Net (Loss) Income Attributable to Common Stock $ (82 ) $ (48 ) $ (84 ) $ 5  
 
Net (loss) income attributable to common stock per share - basic $ (1.70 ) $ (1.13 ) $ (1.81 ) $ 0.12
Net (loss) income attributable to common stock per share - diluted $ (1.70 ) $ (1.13 ) $ (1.81 ) $ 0.12
 
Adjusted net loss $ (14 ) $ (78 ) $ (6 ) $ (121 )
Adjusted net loss per diluted share $ (0.29 ) $ (1.83 ) $ (0.13 ) $ (2.85 )
 
Weighted-average common shares outstanding - basic 48.2 42.4 46.3 42.4
Weighted-average common shares outstanding - diluted 48.2 42.4 46.3 42.7
 
Adjusted EBITDAX $ 245 $ 161 $ 495 $ 361
Effective tax rate 0 % 0 % 0 % 0 %
 
(a) We adopted the new revenue recognition standard on January 1,
2018 which required certain sales related costs to be reported as
expense as opposed to being netted against revenue. The adoption of
this standard does not affect net income. Results for reporting
periods beginning after January 1, 2018 are presented under the new
accounting standard while prior periods are not adjusted and
continue to be reported under accounting standards in effect for the
prior period. Under prior accounting standards total revenues and
other for the three months and the six months ended June 30, 2018
would have been $513 million and $1,080 million, respectively, and
other expenses, net for the three months and the six months ended
June 30, 2018 would have been $13 million and $32 million,
respectively.
 

Cash Flow Data:

Net cash provided (used) by operating activities $ 34 $ (13 ) $ 234 $ 120
Net cash used in investing activities $ (669 ) $ (74 ) $ (807 ) $ (74 )
Net cash provided (used) by financing activities $ 183 $ 46 $ 595 $ (49 )
 

Balance Sheet Data:

June 30, December 31,
  2018     2017  
Total current assets $ 559 $ 483
Total property, plant and equipment, net $ 6,334 $ 5,696
Total current liabilities $ 893 $ 732
Long-term debt $ 5,075 $ 5,306
Mezzanine equity $ 735 $
Equity $ (645 ) $ (720 )
 
Outstanding shares as of 48.4 42.9
 
 
STOCK-BASED COMPENSATION
 
Our stock price increased $36.89 or over 430% from $8.55 as of June
30, 2017 to $45.44 as of June 30, 2018. Due to our stock price
increase, we recognized a significant increase in stock-based
compensation expense that is included in both general and
administrative expenses and production costs as shown in the
following table:
 
Second Quarter Six Months
($ in millions)   2018     2017     2018     2017  
 
General and administrative expenses
Cash-settled awards $ 19 $ $ 22 $ 1
Equity-settled awards   4     4     7     7  
Total stock-based compensation in G&A $ 23   $ 4   $ 29   $ 8  
Total stock-based compensation in G&A per Boe $ 1.89 $ 0.34 $ 1.24 $ 0.34
 
Production costs
Cash-settled awards $ 5 $ $ 6 $
Equity-settled awards   1     1     2     2  
Total stock-based compensation in production costs $ 6   $ 1   $ 8   $ 2  
Total stock-based compensation in production costs per Boe $ 0.49 $ 0.08 $ 0.34 $ 0.08
       
Total company stock-based compensation $ 29   $ 5   $ 37   $ 10  
Total company stock-based compensation per Boe $ 2.38 $ 0.42 $ 1.58 $ 0.42
Attachment 2
PRODUCTION STATISTICS
       
Second Quarter Six Months
Net Oil, NGLs and Natural Gas Production Per Day 2018   2017 2018   2017
 
Oil (MBbl/d)
San Joaquin Basin 54 52 52 52
Los Angeles Basin 25 26 24 27
Ventura Basin 4 5 4 5
Sacramento Basin
Total 83 83 80 84
 
NGLs (MBbl/d)
San Joaquin Basin 15 15 15 15
Los Angeles Basin
Ventura Basin 1 1 1 1
Sacramento Basin
Total 16 16 16 16
 
Natural Gas (MMcf/d)
San Joaquin Basin 172 141 157 141
Los Angeles Basin 1 1 1
Ventura Basin 8 8 7 8
Sacramento Basin 29 33 31 33
Total 210 182 196 183
       
Total Production (MBoe/d) (a) 134 129 129 131
 
 
(a) Natural gas volumes have been converted to BOE based on the
equivalence of energy content between six Mcf of natural gas and one
Bbl of oil. Barrels of oil equivalence does not necessarily result
in price equivalence.
Attachment 3
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
 

Our results of operations can include the effects of unusual,
out-of-period and infrequent transactions and events affecting
earnings that vary widely and unpredictably (in particular certain
non-cash items such as derivative gains and losses) in nature,
timing, amount and frequency. Therefore, management uses a measure
called adjusted net income (loss) which excludes those items. This
measure is not meant to disassociate items from management's
performance, but rather is meant to provide useful information to
investors interested in comparing our performance between periods.
Reported earnings are considered representative of management's
performance over the long term. Adjusted net income (loss) is not
considered to be an alternative to net income (loss) reported in
accordance with U.S. generally accepted accounting principles
(GAAP).

 

We define adjusted EBITDAX as earnings before interest expense;
income taxes; depreciation, depletion and amortization;
exploration expense; other unusual, out-of-period and infrequent
items and other non-cash items. We believe adjusted EBITDAX
provides useful information in assessing our financial condition,
results of operations and cash flows and is widely used by the
industry, the investment community and our lenders. While adjusted
EBITDAX is a non-GAAP measure, the amounts included in the
calculation of adjusted EBITDAX were computed in accordance with
GAAP. A version of this measure is a material component of certain
of our financial covenants under our 2014 revolving credit
facility and is provided in addition to, and not as an alternative
for, income and liquidity measures calculated in accordance with
GAAP. Certain items excluded from adjusted EBITDAX are significant
components in understanding and assessing our financial
performance, such as our cost of capital and tax structure, as
well as the historic cost of depreciable and depletable assets.
Adjusted EBITDAX should be read in conjunction with the
information contained in our financial statements prepared in
accordance with GAAP.

 
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of the GAAP financial
measure of net income (loss) attributable to common stock to the
non-GAAP financial measure of Adjusted net loss and presents the
GAAP financial measure of net (loss) income attributable to common
stock per diluted share and the non-GAAP financial measure of
Adjusted net loss per diluted share:
 
  Second Quarter   Six Months
($ millions, except per share amounts)   2018       2017     2018       2017  
Net (loss) income attributable to common stock $ (82 ) $ (48 ) $ (84 ) $ 5
Unusual, infrequent and other items:
Non-cash derivative loss (gain), excluding noncontrolling interest 92 (35 ) 99 (110 )
Early retirement and severance costs 2 4 3
Gain on asset divestitures (1 ) (1 ) (21 )
Net gain on early extinguishment of debt (24 ) (24 ) (4 )
Other, net   (1 )   5         6  
Total unusual, infrequent and other items 68 (30 ) 78 (126 )
       
Adjusted net loss $ (14 ) $ (78 ) $ (6 ) $ (121 )
 
Net (loss) income attributable to common stock per diluted share $ (1.70 ) $ (1.13 ) $ (1.81 ) $ 0.12
Adjusted net loss per diluted share $ (0.29 ) $ (1.83 ) $ (0.13 ) $ (2.85 )
 
 
DERIVATIVE GAINS AND LOSSES
Second Quarter Six Months
($ millions)   2018     2017     2018     2017  
Non-cash derivative (loss) gain, excluding noncontrolling interest $ (92 ) $ 35 $ (99 ) $ 110
Non-cash derivative loss included in noncontrolling interest (7 ) (7 ) (1 )
Net (payments) proceeds on settled commodity derivatives   (68 )   8     (99 )   7  
Net derivative (loss) gain from commodity contracts $ (167 ) $ 43   $ (205 ) $ 116  
 
 
FREE CASH FLOW
Second Quarter Six Months
($ millions)   2018     2017     2018     2017  
 
Net cash provided (used) by operating activities $ 34 $ (13 ) $ 234 $ 120
Capital investment   (188 )   (82 )   (327 )   (132 )
Free cash flow (154 ) (95 ) (93 ) (12 )
BSP funded capital investment   18     28     18     43  
Free cash flow excluding BSP funded capital $ (136 ) $ (67 ) $ (75 ) $ 31  
 
 
ADJUSTED EBITDAX AND CORE ADJUSTED EBITDAX
The following tables present a reconciliation of the GAAP financial
measures of net income (loss) and net cash provided (used) by
operating activities to the non-GAAP financial measures of adjusted
and core adjusted EBITDAX.
 
Second Quarter Six Months
($ millions)   2018     2017     2018     2017  
Net (loss) income $ (63 ) $ (47 ) $ (54 ) $ 5
Interest and debt expense, net 94 83 186 167
Interest income (1 ) (1 )
Depreciation, depletion and amortization 125 138 244 278
Exploration expense 6 6 14 12
Unusual, infrequent and other items (a) 68 (30 ) 78 (126 )
Other non-cash items   16     11     28     25  
Adjusted EBITDAX (A) $ 245 $ 161 $ 495 $ 361
Net payments (proceeds) on settled commodity derivatives 68 (8 ) 99 (7 )
Cash-settled stock-based compensation   24         28     1  
Core Adjusted EBITDAX (b) $ 337   $ 153   $ 662   $ 355  
 
Net cash provided (used) by operating activities $ 34 $ (13 ) $ 234 $ 120
Cash interest 154 151 215 195
Exploration expenditures 4 6 10 11
Changes in operating assets and liabilities 55 12 37 29
Other, net   (2 )   5     (1 )   6  
Adjusted EBITDAX (A) $ 245 $ 161 $ 495 $ 361
Net payments (proceeds) on settled commodity derivatives 68 (8 ) 99 (7 )
Cash-settled stock-based compensation   24         28     1  
Core Adjusted EBITDAX (b) $ 337   $ 153   $ 662   $ 355  
 
 
(a) See Adjusted Net Income (Loss) reconciliation.
 
(b) Core Adjusted EBITDAX removes the transitory effects of settled
hedges, which in 2018 limited CRC's full price realization. Our
hedging strategy for 2019 has changed and we are not putting caps on
price. Similarly, the significant run-up in our stock price has had
a significant effect on our equity compensation costs due to a
cumulative catch-up effect. The 2018 Core Adjusted EBITDAX
demonstrates our cash generation capacity, taking into account our
new hedging strategy going into 2019.
 
 
ADJUSTED EBITDAX MARGIN
Second Quarter Six Months
($ millions)   2018     2017     2018     2017  
Total revenues and other $ 549 $ 516 $ 1,158 $ 1,106
Non-cash derivative loss (gain)   99     (35 )   106     (109 )
Adjusted revenues (B) $ 648   $ 481   $ 1,264   $ 997  
Adjusted EBITDAX Margin (A)/(B) 38 % 33 % 39 % 36 %
 
 
PRODUCTION COSTS PER BOE    
Second Quarter Six Months
($ per Boe)   2018     2017     2018     2017  
Production costs $ 18.93 $ 18.34 $ 19.01 $ 18.02
Costs attributable to PSC-type contracts   (1.52 )   (1.16 )   (1.57 )   (1.10 )
Production costs, excluding effects of PSC-type contracts $ 17.41   $ 17.18   $ 17.44   $ 16.92  
Attachment 4
ADJUSTED NET LOSS VARIANCE ANALYSIS
($ millions)
   
2017 2nd Quarter Adjusted Net Loss $ (78 )
 
Price - Oil 121

(a)

Price - NGLs 18
Price - Natural Gas (3 )
Volume 3
Production cost (15 )
Taxes other than on income (6 )
DD&A rate 15
Interest expense (11 )
Adjusted general & administrative expenses (30 )
Net income attributable to noncontrolling interests (18 )
All others (10 )
 
2018 2nd Quarter Adjusted Net Loss $ (14 )
 
 
2017 Six-Month Adjusted Net Loss $ (121 )
 
Price - Oil 224 (a)
Price - NGLs 31
Price - Natural Gas (6 )
Volume (45 )
Production cost (16 )
Taxes other than on income (11 )
DD&A rate 29
Exploration expense (2 )
Interest expense (19 )
Adjusted general & administrative expenses (30 )
Net income attributable to noncontrolling interests (30 )
All others (10 )
 
2018 Six-Month Adjusted Net Loss $ (6 )
 
 
(a) Includes cash settlement payments on commodity derivatives
Attachment 5
CAPITAL INVESTMENTS        
Second Quarter Six Months
($ millions) 2018   2017 2018   2017
 
Internally Funded Capital $ 170 $ 45 $ 309 $ 80
 
BSP Funded Capital 18 37 18 52
       
Consolidated Reported Capital Investments $ 188 $ 82 $ 327 $ 132
 
MIRA Funded Capital 6 8 28 8
       
Total Capital Program $ 194 $ 90 $ 355 $ 140
 
 
 
NONCONTROLLING INTEREST DETAIL    
Second Quarter Six Months
($ millions) 2018 2017 2018 2017
 
Distributions to noncontrolling interest holders
BSP Joint Venture $ 4 $ 1 $ 17 $ 1
Ares Joint Venture   19     24  
Total $ 23 $ 1 $ 41 $ 1
Attachment 6
PRICE STATISTICS        
Second Quarter Six Months
  2018       2017     2018       2017  
Realized Prices
Oil with hedge ($/Bbl) $ 64.11 $ 47.98 $ 63.47 $ 49.12
Oil without hedge ($/Bbl) $ 73.19 $ 46.95 $ 70.35 $ 48.70
 
NGLs ($/Bbl) $ 42.13 $ 30.08 $ 42.63 $ 32.20
 
Natural gas ($/Mcf) (a) $ 2.25 $ 2.47 $ 2.51 $ 2.68
 
Index Prices
Brent oil ($/Bbl) $ 74.90 $ 50.92 $ 71.04 $ 52.79
WTI oil ($/Bbl) $ 67.88 $ 48.29 $ 65.37 $ 50.10
NYMEX gas ($/MMBtu) $ 2.75 $ 3.14 $ 2.81 $ 3.20
 
Realized Prices as Percentage of Index Prices
Oil with hedge as a percentage of Brent 86 % 94 % 89 % 93 %
Oil without hedge as a percentage of Brent 98 % 92 % 99 % 92 %
 
Oil with hedge as a percentage of WTI 94 % 99 % 97 % 98 %
Oil without hedge as a percentage of WTI 108 % 97 % 108 % 97 %
 
NGLs as a percentage of Brent 56 % 59 % 60 % 61 %
NGLs as a percentage of WTI 62 % 62 % 65 % 64 %
 
Natural gas as a percentage of NYMEX (a) 82 % 79 % 89 % 84 %
 
(a) See Note (a) on Attachment 1 related to our adoption of the new
accounting standard related to the reporting of certain sales
related costs. For the three months and six months ended June 30,
2018, the realized gas price would have been $2.06 per Mcf and $2.28
per Mcf, respectively, and the realized gas price as a percentage of
NYMEX would have been 75% and 81%, respectively.
Attachment 7
SECOND QUARTER DRILLING ACTIVITY
  San Joaquin   Los Angeles   Ventura   Sacramento  
Wells Drilled (Gross) Basin Basin Basin Basin Total
 
Development Wells
Primary 3 3
Waterflood 3 15 18
Steamflood 51 51
Unconventional 11 11
Total 68 15 83
 
Exploration Wells
Primary
Waterflood
Steamflood
Unconventional
Total
         
Total Wells (a) 68 15 83
         
CRC Wells Drilled 36 12 48
         
BSP Wells Drilled 2 3 5
         
MIRA Wells Drilled 30 30
 
(a) Includes steam injectors and drilled but uncompleted
wells, which would not be included in the SEC definition of wells
drilled.

Attachment 8

HEDGES - CURRENT                
 
3Q 4Q 1Q 2Q 3Q 4Q FY FY
2018 2018 2019 2019 2019 2019 2020   2021
Crude Oil
Sold Calls:
Barrels per day 6,127 16,086 16,057 6,023 991 961 503
Weighted-average Brent price per barrel $60.24 $58.91 $65.75 $67.01 $60.00 $60.00 $60.00 $—
 
Purchased Calls:
Barrels per day 2,000
Weighted-average Brent price per barrel $— $— $71.00 $— $— $— $— $—
 
Purchased Puts:
Barrels per day 6,922 1,851 34,793 36,733 31,676 21,623 1,506 574
Weighted-average Brent price per barrel $61.31 $51.70 $62.77 $67.40 $70.50 $73.09 $47.97 $45.00
 
Sold Puts:
Barrels per day 24,000 19,000 35,000 30,000 30,000 20,000
Weighted-average Brent price per barrel $46.04 $45.00 $50.71 $55.00 $56.67 $60.00 $— $—
 
Swaps:
Barrels per day 48,000 29,000 7,000
Weighted-average Brent price per barrel $60.35 $60.50 $67.71 $— $— $— $— $—
 
A small portion of the crude oil derivatives in the table above were
entered into by the BSP JV, including all of the 2020 and 2021
hedges. This joint venture also entered into natural gas swaps for
insignificant volumes for periods through May 2021.
 
 
Certain of our counterparties have options to increase swap volumes
by up to:
- 19,000 barrels per day at a weighted-average Brent price of $60.13
for the fourth quarter of 2018 and
- 5,000 barrels per day at a weighted-average Brent price of $70.00
for the first quarter of 2019.
 
 
In May 2018 we entered into derivative contracts that limit our
interest rate exposure with respect to $1.3 billion of our
variable-rate indebtedness. The interest rate contracts reset
monthly and require the counterparties to pay any excess interest
owed on such amount in the event the one-month LIBOR exceeds 2.75%
for any monthly period prior to May 4, 2021.
Attachment 9
2018 THIRD QUARTER GUIDANCE
 
Anticipated Realizations Against the Prevailing Index Prices for
Q3 2018
(a)
Oil 95% to 100% of Brent
NGLs 55% to 60% of Brent
Natural Gas 100% to 110% of NYMEX
 
2018 Third Quarter Production, Capital and Income Statement
Guidance
Production (b) 134 to 138 MBOE per day

Capital

$180 million to $200 million

Production costs (b)

$18.60 to $20.10 per BOE

Adjusted general and administrative expenses (b) & (c)

$6.60 to $6.90 per BOE
Depreciation, depletion and amortization (b) $10.05 to $10.35 per BOE
Taxes other than on income $42 million to $46 million
Exploration expense $6 million to $10 million

Interest expense (d)

$94 million to $98 million

Cash interest (d)

$66 million to $70 million
Income tax expense rate 0%
Cash tax rate 0%
 
 

Pre-tax 2018 Third Quarter Price Sensitivities (e)

$1 change in Brent index - Oil (f)

$1.6 million
$1 change in Brent index - NGLs $0.9 million
$0.50 change in NYMEX - Gas $4.9 million
 
 
(a) Realizations exclude hedge effects.
 
(b) Based on average Q2 2018 Brent of $75.
 

(c) Our long-term incentive compensation programs for
non-executive employees are stock-based but payable in cash.
Accounting rules require that we adjust the cumulative liability
for all vested but yet unpaid awards under these programs to the
amount that would be paid using our stock price as of the end of
each quarter. Therefore, in addition to the normal pro-rata
vesting expense associated with these programs, our quarterly G&A
expense could include this cumulative adjustment depending on
movement in our stock price. Our stock price at June 30, 2018 was
$45.44 per share, which was used for third quarter guidance. Only
about 1/3 of such cumulative adjustment would result in a cash
liability in the same year as the adjustment because of the
pro-rata three-year vesting of our incentive compensation programs.

 

(d) Interest expense includes cash interest, original issue
discount and amortization of deferred financing costs as well as
the deferred gain that resulted from the December 2015 debt
exchange. Cash interest for the quarter is lower than interest
expense due to the timing of interest payments.

 

(e) Due to our tax position there is no difference between the
impact on our income and cash flows.

 

(f) Amount reflects the sensitivity with respect to unhedged
barrels at a Brent index price exceeding $60.00 per barrel and
includes the effect of production sharing type contracts at our
Wilmington field operations in Long Beach.

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