California Resources Corporation (NYSE: CRC), an independent
California-based oil and gas exploration and production company,
today reported net income attributable to common stock of $94
million, or $1.89 per diluted share, for the third quarter of 2019.
Adjusted net income1 was $17 million, or $0.35 per diluted share.
Operational and financial highlights for the third quarter of 2019
were as follows:
Third Quarter Highlights
- Reported adjusted EBITDAX1 of $278 million; adjusted EBITDAX
margin1 of 41%; net cash provided by operating activities of $268
million; free cash flow1 of $151 million after taking into account
CRC's internally funded capital.
- Implemented a more efficient organizational design, resulting
in anticipated ongoing annual cost savings of approximately $50
million starting in the fourth quarter of 2019
- Delivered average production of 128,000 barrels of oil
equivalent (BOE) per day including 79,000 barrels per day of
oil
- Invested $188 million of total capital, including $117 million
of internally funded capital
- Drilled 82 wells in the San Joaquin basin, 8 wells in the Los
Angeles basin and 1 exploratory well in the Ventura basin,
including JV wells
- Repurchased $153 million face value of Second Lien Notes for
$90 million
- Secured a credit agreement amendment to provide future
flexibility in connection with potential royalty transactions
Todd Stevens, CRC's President and Chief Executive Officer, said,
"CRC's start to the second half of the year highlights our
continued focus on controlling what we can control by maintaining
capital discipline, opportunistically repurchasing debt to
strengthen our balance sheet, improving our credit position,
reducing costs and enhancing margins. Our previously announced JV
partnership with Alpine ramped up quickly, having drilled 52 wells
through the end of the third quarter, with the majority of the
wells being accretive to production beginning in the fourth
quarter. We were also excited to receive a grant from the
Department of Energy for a FEED study to advance CO2 capture and
sequestration at Elk Hills, which could potentially add well over
150 MMBOE of EOR reserves, reduce our greenhouse gas emissions and
in turn lower costs."
Mr. Stevens continued, "Additionally, we are pleased we were
able to repurchase over $150 million face value of our Second Lien
Notes at a significant discount as well as secure our ninth credit
amendment during the quarter. We remain committed to pursuing
additional transactions to progress towards our balance sheet goals
while driving value through a balanced approach of debt repurchases
with investments in our large project inventory."
Third Quarter 2019
Results
For the third quarter of 2019, CRC reported net income
attributable to common stock (CRC net income) of $94 million, or
$1.89 per diluted share, compared to $66 million, or $1.32 per
diluted share, for the same period of 2018. Adjusted net income1
for the third quarter of 2019 was $17 million, or $0.35 per diluted
share, compared to $41 million, or $0.81 per diluted share, for the
same period in 2018. Adjusted net income1 excluded a net gain of
$82 million on debt repurchases, non-cash losses on commodity
derivatives of $6 million and income of $1 million, net, for other
unusual and infrequent items.
Adjusted EBITDAX1 for the third quarter of 2019 was $278 million
and cash provided by operating activities was $268 million.
Total daily production volumes decreased 6% year-over-year, from
136,000 BOE per day for the third quarter of 2018 to 128,000 BOE
per day for the third quarter of 2019. Oil volumes in the third
quarter of 2019 averaged 79,000 barrels per day, NGL volumes
averaged 16,000 barrels per day and gas volumes averaged 196,000
thousand cubic feet (Mcf) per day. The decrease was due to the Lost
Hills divestiture, lower capital investment including fewer
workovers, power outages and other factors. The divestiture reduced
our third quarter 2019 production by over 2,000 BOE per day
compared to the same quarter of 2018.
Despite lower Brent index prices, our realized crude oil prices,
including the effect of settled hedges, increased by $4.78 per
barrel from $63.63 in the third quarter of 2018 to $68.41 per
barrel in the third quarter of 2019. In the third quarter of 2019,
hedge settlements increased our realized crude oil prices by $5.56
per barrel compared to a reduction of $10.10 per barrel in the same
prior-year period. Realized NGL prices were $23.55 per barrel, down
$22.17 per barrel over the prior-year period as local and national
markets continued to experience excess domestic supply coupled with
weaker demand due to Los Angeles and Bay area refinery downtimes.
Realized natural gas prices were $2.73 per Mcf for the third
quarter of 2019, $0.43 per Mcf lower than the same prior-year
period due to milder temperatures and more pipeline availability
within local California markets in 2019 compared to 2018.
Production costs for the third quarter of 2019 were $221
million, compared to $236 million for the third quarter of 2018. On
a per barrel basis, for the same comparative periods, production
costs were $18.82 and $18.92, respectively. The decrease is
primarily due to cost savings from the Lost Hills divestiture,
lower surface operations costs, lower field employee-related costs
and lower downhole maintenance spending, partially offset by higher
energy prices. Excluding the effect of PSC-type contracts,
production costs on a per barrel basis for the same comparative
periods would have been $17.44 and $17.55, respectively.
General and administrative (G&A) expenses were $66 million
for the third quarter of 2019, compared to $81 million for the same
prior-year period. The decrease was primarily attributable to a
lower stock price resulting in a $13 million decrease in
cash-settled stock-based compensation expense.
CRC reported taxes other than on income of $42 million for the
third quarter of 2019, compared to $45 million for the same
prior-year period. Exploration expense was $5 million for the third
quarter of 2019, $1 million higher than the same prior-year
period.
Total capital invested during the quarter of 2019 was $188
million, within our guidance. CRC internally funded $117 million,
of which $101 million was directed to drilling and capital
workovers. CRC's JV partner Benefit Street Partners (BSP) also
invested $5 million, which is included in CRC's consolidated
results. CRC's JV partners Macquarie Infrastructure and Real Assets
Inc. (MIRA) and Alpine Energy Capital, LLC (Alpine) invested an
additional $3 million and $63 million, respectively, which are
excluded from CRC's consolidated results.
Cash provided by operating activities for the third quarter of
2019 was $268 million and free cash flow1 was $151 million after
taking into account CRC's internally funded capital.
Nine-Month Results
For the first nine months of 2019, CRC net income was $39
million, or $0.77 per diluted share, compared to a net loss
attributable to common stock of $18 million, or $0.38 per diluted
share, for the same period of 2018. Including hedge settlements,
the 2019 results reflected higher year-over-year revenue despite a
lower oil price environment. Adjusted net income1 for the first
nine months of 2019 was $34 million, or $0.69 per diluted share,
compared with an adjusted net income1 of $35 million, or $0.71 per
diluted share, for the same period of 2018. The 2019 adjusted net
income1 excluded $99 million of non-cash derivative losses, a net
gain of $108 million from debt repurchases and a net $4 million
charge related to other unusual and infrequent items.
Total daily production volumes averaged 130,000 BOE per day for
the first nine months of 2019, compared with 131,000 BOE per day
for the same period in 2018, a decrease of 1 percent. The 2018
volumes reflect two quarters of production from the Elk Hills
acquisition. The 2019 volumes reflect the effect of the strategic
Lost Hills divestiture that occurred in the second quarter of
2019.
In the first nine months of 2019, realized crude oil prices,
including the effect of settled hedges, increased $4.63 per barrel
to $68.16 per barrel from $63.53 per barrel for the same period in
2018. Settled hedges increased 2019 realized crude oil prices by
$3.13 per barrel, compared with a reduction of $8.00 per barrel for
the same period in 2018. Realized NGL prices decreased 29 percent,
or $12.67 per barrel to $31.04 per barrel in the first nine months
of 2019 from $43.71 per barrel for the same period of 2018.
Realized natural gas prices increased $0.09 per Mcf to $2.82 per
Mcf, compared with $2.73 per Mcf for the same period in 2018,
largely due to stronger California demand.
Production costs for the first nine months of 2019 were $684
million, or $19.32 per BOE, compared to $679 million, or $18.98 per
BOE, for the same period in 2018. The increase in production costs
was primarily attributable to the Elk Hills transaction, higher
surface operations and maintenance costs, energy costs and other
items, partially offset by lower downhole maintenance activity and
lower costs resulting from the Lost Hills divestiture. Per unit
production costs, excluding the effect of PSCs1, were $17.82 and
$17.48 per BOE for the first nine months of 2019 and 2018,
respectively.
G&A expenses for the first nine months of 2019 were $228
million, compared to $234 million in the prior-year period, with
the decrease largely due to lower equity compensation expense in
the first nine months of 2019. This decrease was partially offset
by higher expenses across a number of functions.
Taxes other than on income of $119 million for the first nine
months of 2019 were comparable to the same period of 2018, when
taxes were $120 million. Exploration expense of $25 million for the
first nine months of 2019 was $7 million higher than the same
period of 2018.
CRC's internally funded capital investment in the first nine
months of 2019 totaled $345 million, of which $259 million was
directed to drilling and capital workovers. CRC's JV partners
invested $121 million in the first nine months of 2019, all of
which was directed to drilling. Of our JV partners' investment, BSP
invested $48 million which is included in CRC's consolidated
results.
Cash provided by operating activities for the first nine months
of 2019 was $540 million and free cash flow1 was $195 million after
taking into account CRC's internally funded capital.
Operational Update
In the third quarter of 2019, CRC operated an average of ten
drilling rigs, with 3 on primary, 3 on waterfloods and 4 on
unconventional production. With total invested capital, we drilled
90 development wells (47 primary, 27 waterflood, and 16
unconventional) and one exploration well. 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 period
that the well is drilled. The San Joaquin basin produced 94,000 BOE
per day and operated seven rigs. The Los Angeles basin contributed
24,000 BOE per day of production and operated two rigs directed
toward waterflood projects. The Ventura basin produced 5,000 BOE
per day and operated one rig focused on exploration and the
Sacramento basin, where we had no active CRC drilling program,
produced 5,000 BOE per day.
2019 Capital Budget
CRC expects its 2019 internally funded capital program will
range from $385 million to $400 million, of which $345 million has
been invested through the third quarter of 2019. We have front
loaded our internally funded capital investments for 2019. With
additional investment from new and existing JV partners, CRC
anticipates JV investment of $200 to $225 million for 2019, of
which $121 million has been invested through the third quarter of
2019. CRC anticipates a total capital program of approximately $585
to $625 million for the year. Our 2019 capital is focused on oil
and largely directed to short payout projects, such as primary
drilling of both vertical and lateral wells, capital workovers and
low-risk projects including waterflood and steamflood investments
that maintain base production.
Recent Joint Venture
In July 2019, we entered into a development agreement with
Alpine to develop portions of CRC's Elk Hills field. Alpine is a
joint venture between subsidiaries of Colony Capital, Inc. (Colony)
and Equity Group Investments. Alpine committed to invest $320
million, which may be increased to a total investment of $500
million, subject to the mutual agreement of the parties. The
initial commitment will cover multiple development opportunities
and is intended to be invested over approximately three years in
accordance with a 275-well development plan. Alpine will fund 100%
of the development wells and will earn a 90% working interest in
those wells. If Alpine receives an agreed upon return, CRC's
working interest in those wells will increase from 10% to
82.5%.
In connection with this joint venture, Colony received a warrant
to purchase up to 1.25 million shares of CRC's common stock, at an
exercise price of $40 per share.
Repurchases and Balance Sheet
Update
During the third quarter of 2019, CRC repurchased $153 million
in face value of Second Lien Notes for $90 million, bringing the
aggregate face value repurchased since issuance to $412 million,
including $229 million during the first nine months of 2019. Net
debt outstanding at the end of the third quarter was under $5.0
billion. CRC also secured a ninth amendment to our credit agreement
which provides future flexibility in connection with potential
royalty transactions.
The semi-annual borrowing base review under the Company's 2014
Revolving Credit Facility is finalized in early May and early
November of each year. The process is currently underway and is
well advanced.
Hedging Update
CRC continues to execute an opportunistic hedging program to
protect its cash flow, operating margins and capital program, while
maintaining adequate liquidity. For the fourth quarter of 2019, CRC
has protected the downside price risk on 35,000 barrels per day at
approximately $76 Brent with put spreads. These put spreads provide
full upside to oil price movements and downside protection when
Brent drops below $60 per barrel, at which point we receive Brent
plus approximately $16 per barrel. For the first and second
quarters of 2020, CRC has protected the downside risk of 30,000 and
15,000 barrels per day at approximately $71 Brent and $68 Brent,
respectively. These put spreads provide downside price protection
when Brent prices drop below $57 and $55 per barrel in the first
and second quarters, respectively, at which point CRC receives
Brent plus approximately $14 per barrel. CRC also entered into a
swap for 5,000 barrels per day in the second quarter of 2020 at
approximately $70 Brent, which may be increased by another 5,000
barrels per day at the same price at the option of the
counterparties. For the third and fourth quarters of 2020, CRC has
protected the downside risk of 10,000 and 5,000 barrels per day,
respectively, at $65 per barrel. These put spreads provide downside
protection when Brent prices drop below $55, at which point CRC
receives Brent plus approximately $10 per barrel. See Attachment 8
for more details.
1 See Attachment 3 for non-GAAP financial measures of adjusted
EBITDAX, adjusted EBITDAX margin, production costs (excluding
effects of PSC-type contracts), adjusted net income (loss) and free
cash flow, including reconciliations to their most directly
comparable GAAP measure, where applicable.
Conference Call Details
To participate in Monday's conference call scheduled for
November 4th, 2019 at 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/10134619. 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. CRC 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 CRC's
expectations as to its future:
- financial position, liquidity, cash flows and results of
operations
- business prospects
- transactions and projects
- operating costs
- Value Creation Index (VCI) metrics, which are based on certain
estimates including future production rates, costs and commodity
prices
- operations and operational results including production,
hedging and capital investment
- budgets and maintenance capital requirements
- reserves
- type curves
- expected synergies from acquisitions and joint ventures
Actual results may differ from anticipated results, sometimes
materially, and reported results should not be considered an
indication of future performance. While CRC believes assumptions or
bases underlying its expectations are reasonable and makes them in
good faith, they almost always vary from actual results, sometimes
materially. CRC also believes third-party statements it cites are
accurate, but has not independently verified them and does not
warrant their accuracy or completeness. Factors (but not
necessarily all the factors) that could cause results to differ
include:
- commodity price changes
- debt limitations on CRC's financial flexibility
- insufficient cash flow to fund CRC's capital plan, planned
investments, debt repurchases and distributions to JV partners
- inability to enter into desirable transactions, including
acquisitions, 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 CRC's
products
- joint ventures and acquisitions and CRC's ability to achieve
expected synergies
- the recoverability of resources and unexpected geologic
conditions
- incorrect estimates of reserves and related future cash flows
and the inability to replace reserves
- changes in business strategy
- PSC effects on production and unit production costs
- effect of stock price on costs associated with incentive
compensation
- insufficient capital, including as a result of lender
restrictions, unavailability of capital markets or inability to
attract potential investors
- effects of hedging transactions
- 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, joint ventures 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 “Item 1A - Risk Factors” in CRC's Annual
Report on Form 10-K available on its website at crc.com.
Words such as "anticipate," "believe," "continue," "could,"
"estimate," "expect," "goal," "intend," "likely," "may," "might,"
"plan," "potential," "project," "seek," "should," "target, "will"
or "would" and similar words that reflect the prospective nature of
events or outcomes typically identify forward-looking statements.
Any forward-looking statement speaks only as of the date on which
such statement is made and 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.
Attachment 1
SUMMARY OF RESULTS
Third Quarter
Nine Months
($ and shares in millions, except per
share amounts)
2019
2018
2019
2018
Statements of Operations:
Revenues and Other
Oil and gas sales
$
541
$
700
$
1,720
$
1,932
Net derivative gain (loss) from commodity
contracts
37
(54
)
(31
)
(259
)
Other revenue
103
182
335
313
Total revenues and other
681
828
2,024
1,986
Costs and Other
Production costs
221
236
684
679
General and administrative expenses
66
81
228
234
Depreciation, depletion and
amortization
118
128
357
372
Taxes other than on income
42
45
119
120
Exploration expense
5
4
25
18
Other expenses, net
81
149
284
259
Total costs and other
533
643
1,697
1,682
Operating Income
148
185
327
304
Non-Operating (Loss) Income
Interest and debt expense, net
(95
)
(95
)
(293
)
(281
)
Net gain on early extinguishment of
debt
82
2
108
26
Gain on asset divestitures
—
3
—
4
Other non-operating expenses
(8
)
(4
)
(18
)
(16
)
Income Before Income Taxes
127
91
124
37
Income tax
—
—
—
—
Net Income
127
91
124
37
Net income attributable to noncontrolling
interests
(33
)
(25
)
(85
)
(55
)
Net Income (Loss) Attributable to
Common Stock
$
94
$
66
$
39
$
(18
)
Net income (loss) attributable to common
stock per share - basic
$
1.89
$
1.34
$
0.78
$
(0.38
)
Net income (loss) attributable to common
stock per share - diluted
$
1.89
$
1.32
$
0.77
$
(0.38
)
Adjusted net income
$
17
$
41
$
34
$
35
Adjusted net income per share - basic
$
0.35
$
0.82
$
0.70
$
0.72
Adjusted net income per share -
diluted
$
0.35
$
0.81
$
0.69
$
0.71
Weighted-average common shares outstanding
- basic
49.1
48.5
48.9
47.0
Weighted-average common shares outstanding
- diluted
49.2
49.1
49.2
47.0
Adjusted EBITDAX
$
278
$
308
$
834
$
803
Effective tax rate
0
%
0
%
0
%
0
%
Cash Flow
Data:
Net cash provided by operating
activities
$
268
$
159
$
540
$
393
Net cash used in investing activities
$
(121
)
$
(158
)
$
(291
)
$
(965
)
Net cash (used) provided by financing
activities
$
(152
)
$
(12
)
$
(244
)
$
583
September 30,
December 31,
($ and shares in millions)
2019
2018
Selected Balance Sheet Data:
Total current assets
$
510
$
640
Total property, plant and equipment,
net
$
6,403
$
6,455
Total current liabilities
$
721
$
607
Long-term debt
$
4,896
$
5,251
Other long-term liabilities
$
679
$
575
Mezzanine equity
$
789
$
756
Equity
$
(208
)
$
(247
)
Outstanding shares
49.1
48.7
STOCK-BASED COMPENSATION
Our consolidated results of operations for
the three months and nine months ended September 30, 2019 and 2018
include the effects of long-term stock-based compensation plans
under which awards are granted annually to executives,
non-executive employees and non-employee directors that are either
settled with shares of our common stock or cash. Our equity-settled
awards granted to executives include stock options, restricted
stock units and performance stock units that either cliff vest at
the end of a three-year period or vest ratably over a three year
period, some of which are partially settled in cash. Our
equity-settled awards granted to non-employee directors are
restricted stock grants that either vest immediately or restricted
stock units that cliff vest after one year. Our cash-settled awards
granted to non-executive employees vest ratably over a three-year
period.
Changes in our stock price introduce
volatility in our results of operations because we pay cash-settled
awards based on our stock price on the vesting date and accounting
rules require that we adjust our obligation for unvested awards to
the amount that would be paid using our stock price at the end of
each reporting period. Cash-settled awards, including executive
awards partially settled in cash, account for over 50% of our total
outstanding awards. Equity-settled awards are not similarly
adjusted for changes in our stock price.
Stock-based compensation is included in
both general and administrative expenses and production costs as
shown in the table below:
Third Quarter
Nine Months
($ in millions, except per BOE
amounts)
2019
2018
2019
2018
General and administrative
expenses
Cash-settled awards
$
(2
)
$
11
$
11
$
33
Equity-settled awards
3
2
10
10
Total in G&A
$
1
$
13
$
21
$
43
Total in G&A per Boe
$
0.09
$
1.04
$
0.59
$
1.20
Production costs
Cash-settled awards
$
—
$
2
$
4
$
8
Equity-settled awards
1
1
3
3
Total in production costs
$
1
$
3
$
7
$
11
Total in production costs per Boe
$
0.09
$
0.24
$
0.20
$
0.31
Total company
$
2
$
16
$
28
$
54
Total company per Boe
$
0.18
$
1.28
$
0.79
$
1.51
DERIVATIVE GAINS AND LOSSES
The following table presents the
components of our net derivative gains and losses from commodity
contracts and our non-cash derivative gain and loss from
interest-rate contracts. Our non-cash derivative gain and loss from
interest-rate contracts is reported in other non-operating
expenses.
Third Quarter
Nine Months
($ millions)
2019
2018
2019
2018
Commodity Contracts:
Non-cash derivative (loss) gain excluding
noncontrolling interest
$
(6
)
$
28
$
(99
)
$
(71
)
Non-cash derivative gain (loss) -
noncontrolling interest
3
(3
)
—
(10
)
Total non-cash changes
(3
)
25
(99
)
(81
)
Net proceeds (payments) on settled
commodity derivatives
40
(79
)
68
(178
)
Net derivative gain (loss) from commodity
contracts
$
37
$
(54
)
$
(31
)
$
(259
)
Interest-Rate Contracts:
Non-cash derivative gain (loss)
$
—
$
1
$
(4
)
$
—
Attachment 2
PRODUCTION STATISTICS
Third Quarter
Nine Months
Net Oil, NGLs and Natural Gas
Production Per Day
2019
2018
2019
2018
Oil (MBbl/d)
San Joaquin Basin
51
54
53
52
Los Angeles Basin
24
26
24
25
Ventura Basin
4
4
4
4
Total
79
84
81
81
NGLs (MBbl/d)
San Joaquin Basin
16
16
15
16
Ventura Basin
—
1
1
1
Total
16
17
16
17
Natural Gas (MMcf/d)
San Joaquin Basin
162
172
163
162
Los Angeles Basin
2
1
2
1
Ventura Basin
4
6
6
7
Sacramento Basin
28
29
29
30
Total
196
208
200
200
Total Production (MBoe/d)
128
136
130
131
Note: MBbl/d refers to thousands of
barrels per day; MMcf/d refers to millions of cubic feet per day;
MBoe/d refers to thousands of barrels of oil equivalent (Boe) per
day. Natural gas volumes have been converted to Boe based on the
equivalence of energy content of six thousand cubic feet of natural
gas to one barrel 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, which are
presented in accordance with U. S. generally accepted accounting
principles (GAAP), 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 certain
non-GAAP measures to assess our financial condition, results of
operations and cash flows. These measures are widely used by the
industry, the investment community and our lenders. Although these
are non-GAAP measures, the amounts included in the calculations
were computed in accordance with GAAP. Certain items excluded from
these non-GAAP measures 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. These measures should be read in
conjunction with the information contained in our financial
statements prepared in accordance with GAAP.
Below are additional disclosures regarding
each of the non-GAAP measures reported in this press release,
including reconciliations to their most directly comparable GAAP
measure where applicable.
ADJUSTED NET INCOME (LOSS)
Management uses a measure called adjusted
net income (loss) to provide useful information to investors
interested in comparing our core operations between periods and our
performance to our peers. This measure is not meant to disassociate
the effects of unusual, out-of-period and infrequent items
affecting earnings from management's performance but rather is
meant to provide useful information to investors interested in
comparing our financial 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
GAAP. 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 income and
presents the GAAP financial measure of net income (loss)
attributable to common stock per diluted share and the non-GAAP
financial measure of adjusted net income per diluted share.
Third Quarter
Nine Months
($ millions, except per share amounts)
2019
2018
2019
2018
Net income
$
127
$
91
$
124
$
37
Net income attributable to noncontrolling
interests
(33
)
(25
)
(85
)
(55
)
Net income (loss) attributable to common
stock
94
66
39
(18
)
Unusual, infrequent and other items:
Non-cash derivative (gain) loss from
commodities, excluding noncontrolling interest
6
(28
)
99
71
Severance costs
—
—
2
4
Gain on asset divestitures
—
(3
)
—
(4
)
Net gain on early extinguishment of
debt
(82
)
(2
)
(108
)
(26
)
Other, net
(1
)
8
2
8
Total unusual, infrequent and other
items
(77
)
(25
)
(5
)
53
Adjusted net income
$
17
$
41
$
34
$
35
Net income (loss) attributable to common
stock per share - diluted
$
1.89
$
1.32
$
0.77
$
(0.38
)
Adjusted net income per share -
diluted
$
0.35
$
0.81
$
0.69
$
0.71
FREE CASH FLOW
Management uses free cash flow, which is
defined by us as net cash provided by operating activities less
capital investments, as a measure of liquidity. The following table
presents a reconciliation of our net cash provided by operating
activities to free cash flow.
Third Quarter
Nine Months
($ millions)
2019
2018
2019
2018
Net cash provided by operating
activities
$
268
$
159
$
540
$
393
Capital investments
(122
)
(177
)
(393
)
(504
)
Free cash flow
146
(18
)
147
(111
)
BSP funded capital
5
19
48
37
Free cash flow, after internally funded
capital
$
151
$
1
$
195
$
(74
)
ADJUSTED EBITDAX
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. Management uses
adjusted EBITDAX as a measure of operating cash flow without
working capital adjustments. A version of adjusted EBITDAX 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. The following table presents a
reconciliation of the GAAP financial measures of net income (loss)
and net cash provided by operating activities to the non-GAAP
financial measure of adjusted EBITDAX.
Third Quarter
Nine Months
($ millions, except per BOE amounts)
2019
2018
2019
2018
Net income
$
127
$
91
$
124
$
37
Interest and debt expense, net
95
95
293
281
Depreciation, depletion and
amortization
118
128
357
372
Exploration expense
5
4
25
18
Unusual, infrequent and other items
(a)
(77
)
(25
)
(5
)
53
Other non-cash items
10
15
40
42
Adjusted EBITDAX
$
278
$
308
$
834
$
803
Net cash provided by operating
activities
$
268
$
159
$
540
$
393
Cash interest
75
69
300
284
Exploration expenditures
5
4
15
14
Working capital changes
(70
)
76
(21
)
113
Other, net
—
—
—
(1
)
Adjusted EBITDAX
$
278
$
308
$
834
$
803
Adjusted EBITDAX per Boe
$
23.68
$
24.70
$
23.55
$
22.44
(a) See Adjusted Net Income
reconciliation.
DISCRETIONARY CASH FLOW
We define discretionary cash flow as the
cash available after distributions to noncontrolling interest
holders and cash interest, excluding the effect of working capital
changes but before our internal capital investment. Management uses
discretionary cash flow as a measure of the availability of cash to
reduce debt or fund investments.
Third Quarter
Nine Months
($ millions)
2019
2018
2019
2018
Adjusted EBITDAX
$
278
$
308
$
834
$
803
Cash interest
(75
)
(69
)
(300
)
(284
)
Distributions paid to noncontrolling
interest holders:
BSP JV
(30
)
(18
)
(55
)
(35
)
Ares JV
(20
)
(21
)
(60
)
(45
)
Discretionary cash flow
$
153
$
200
$
419
$
439
ADJUSTED EBITDAX MARGIN
Management uses adjusted EBITDAX margin as
a measure of profitability between periods and this measure is
generally used by analysts for comparative purposes within the
industry.
Third Quarter
Nine Months
($ millions)
2019
2018
2019
2018
Total revenues and other
$
681
$
828
$
2,024
$
1,986
Non-cash derivative gain (loss)
3
(25
)
99
81
Revenues, excluding non-cash derivative
gains and losses
$
684
$
803
$
2,123
$
2,067
Adjusted EBITDAX Margin
41
%
38
%
39
%
39
%
ADJUSTED GENERAL AND ADMINISTRATIVE
EXPENSES
Management uses a measure called adjusted
general and administrative expenses to provide useful information
to investors interested in comparing our costs between periods and
our performance to our peers. The following table presents a
reconciliation of the GAAP financial measure of general and
administrative expenses to the non-GAAP financial measure of
adjusted general and administrative expenses.
Third Quarter
Nine Months
2019
2018
2019
2018
General and administrative expenses
$
66
$
81
$
228
$
234
Severance costs and other
(1
)
—
(2
)
(1
)
Adjusted general and administrative
expenses
$
65
$
81
$
226
$
233
PRODUCTION COSTS PER BOE
The reporting of our PSC-type contracts
creates a difference between reported production costs, which are
for the full field, and reported volumes, which are only our net
share, inflating the per barrel production costs. The following
table presents production costs after adjusting for the excess
costs attributable to PSC-type contracts.
Third Quarter
Nine Months
($ per Boe)
2019
2018
2019
2018
Production costs
$
18.82
$
18.92
$
19.32
$
18.98
Excess costs attributable to PSC-type
contracts
(1.38
)
(1.37
)
(1.50
)
(1.50
)
Production costs, excluding effects of
PSC-type contracts
$
17.44
$
17.55
$
17.82
$
17.48
Attachment 4
CAPITAL INVESTMENTS
Third Quarter
Nine Months
($ millions)
2019
2018
2019
2018
Internally funded capital
$
117
$
158
$
345
$
467
BSP funded capital
5
19
48
37
Capital investments - as reported
$
122
$
177
$
393
$
504
MIRA funded capital
3
19
10
46
Alpine funded capital
63
—
63
—
Total capital program
$
188
$
196
$
466
$
550
Attachment 5
PRICE STATISTICS
Third Quarter
Nine Months
2019
2018
2019
2018
Realized Prices
Oil with hedge ($/Bbl)
$
68.41
$
63.63
$
68.16
$
63.53
Oil without hedge ($/Bbl)
$
62.85
$
73.73
$
65.03
$
71.53
NGLs ($/Bbl)
$
23.55
$
45.72
$
31.04
$
43.71
Natural gas ($/Mcf)
$
2.73
$
3.16
$
2.82
$
2.73
Index Prices
Brent oil ($/Bbl)
$
62.00
$
75.97
$
64.74
$
72.68
WTI oil ($/Bbl)
$
56.45
$
69.50
$
57.06
$
66.75
NYMEX gas ($/MMBtu)
$
2.27
$
2.88
$
2.72
$
2.83
Realized Prices as Percentage of Index
Prices
Oil with hedge as a percentage of
Brent
110
%
84
%
105
%
87
%
Oil without hedge as a percentage of
Brent
101
%
97
%
100
%
98
%
Oil with hedge as a percentage of WTI
121
%
92
%
119
%
95
%
Oil without hedge as a percentage of
WTI
111
%
106
%
114
%
107
%
NGLs as a percentage of Brent
38
%
60
%
48
%
60
%
NGLs as a percentage of WTI
42
%
66
%
54
%
65
%
Natural gas as a percentage of NYMEX
120
%
110
%
104
%
96
%
Attachment 6
THIRD QUARTER DRILLING ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
47
—
—
—
47
Waterflood
19
8
—
—
27
Steamflood
—
—
—
—
—
Unconventional
16
—
—
—
16
Total
82
8
—
—
90
Exploration Wells
Primary
—
—
1
—
1
Waterflood
—
—
—
—
—
Steamflood
—
—
—
—
—
Unconventional
—
—
—
—
—
Total
—
—
1
—
1
Total Wells (a)
82
8
1
—
91
CRC wells drilled
29
5
1
—
35
BSP wells drilled
1
3
—
—
4
MIRA wells drilled
—
—
—
—
—
Alpine wells drilled
52
—
—
—
52
(a) Includes steam injectors and drilled
but uncompleted wells, which would not be included in the SEC
definition of wells drilled.
Attachment 7
NINE MONTHS 2019 DRILLING
ACTIVITY
San Joaquin
Los Angeles
Ventura
Sacramento
Wells Drilled
Basin
Basin
Basin
Basin
Total
Development Wells
Primary
53
—
—
—
53
Waterflood
34
22
—
—
56
Steamflood
40
—
—
—
40
Unconventional
32
—
—
—
32
Total
159
22
—
—
181
Exploration Wells
Primary
2
—
2
—
4
Waterflood
—
—
—
—
—
Steamflood
5
—
—
—
5
Unconventional
—
—
—
—
—
Total
7
—
2
—
9
Total Wells (a)
166
22
2
—
190
CRC wells drilled
98
14
2
—
114
BSP wells drilled
15
8
—
—
23
MIRA wells drilled
1
—
—
—
1
Alpine wells drilled
52
—
—
—
52
(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
Q4
Q1
Q2
Q3
Q4
2019
2020
2020
2020
2020
CRUDE OIL
Purchased Puts:
Barrels per day
35,000
30,000
15,000
10,000
5,000
Weighted-average Brent price per
barrel
$75.71
$70.83
$68.33
$65.00
$65.00
Sold Puts:
Barrels per day
35,000
30,000
150,000
10,000
5,000
Weighted-average Brent price per
barrel
$60.00
$56.67
$55.00
$55.00
$55.00
Swaps:
Barrels per day
—
—
5,000
(a)
—
—
Weighted-average Brent price per
barrel
$—
$—
$70.05
$—
$—
(a) Counterparties have the option to
increase swap volumes by up to 5,000 barrels per day at a
weighted-average Brent price of $70.05 for the second quarter of
2020.
The BSP JV entered into crude oil
derivatives for insignificant volumes through 2021 that are
included in our consolidated results but not in the above table.
The BSP JV also entered into natural gas swaps for insignificant
volumes for periods through May 2021. The hedges entered into by
the BSP JV could affect the timing of the redemption of BSP's
noncontrolling interest.
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 2021.
Attachment 9
2019 FOURTH QUARTER GUIDANCE
Anticipated Realizations Against the
Prevailing Index Prices for Q4 2019 (a)
Oil
96% to 101% of Brent
NGLs
40% to 45% of Brent
Natural Gas
110% to 120% of NYMEX
2019 Fourth Quarter Production, Capital
and Income Statement Guidance
Production (assumed Q4 average Brent price
of $60/Bbl)
124 to 129 MBOE per day
Production (assumed Q4 average Brent price
of $65/Bbl)
123 to 128 MBOE per day
Capital (b)
$135 million to $165 million
Production costs (assumed Q4 average Brent
price of $60/Bbl)
$17.70 to $18.80 per BOE
Production costs (assumed Q4 average Brent
price of $65/Bbl)
$17.80 to $18.90 per BOE
Adjusted general and administrative
expenses (c) & (d)
$5.70 to $6.10 per BOE
Depreciation, depletion and amortization
(c)
$10.15 to $10.45 per BOE
Taxes other than on income
$38 million to $42 million
Exploration expense
$4 million to $9 million
Interest expense (e)
$88 million to $93 million
Cash interest (e)
$139 million to $144 million
Effective tax rate
0%
Cash tax rate
0%
Pre-tax 2019 Fourth Quarter Price
Sensitivities (f)
$1 change in Brent index - Oil (g)
$6.5 million
$1 change in Brent index - NGLs
$0.7 million
$0.50 change in NYMEX - Gas
$7.0 million
(a) Realizations exclude hedge
effects.
(b) Capital guidance includes CRC, MIRA
and Alpine capital.
(c) Production based on assumed Q4 average
Brent price of $60/Bbl.
(d) A portion of our long-term incentive
compensation programs are stock based but payable in cash.
Accounting rules require that we adjust our obligation for all
vested but unpaid cash-settled awards under these programs to the
amount that would be paid using our stock price as of the end of
each reporting period. Therefore, in addition to the normal
pro-rata vesting expense associated with these programs, our
quarterly expense could include a cumulative adjustment depending
on movement in our stock price. For example, the third quarter of
2019 reflected an $8 million reduction of our G&A costs as a
result of lower stock price from the second quarter. Our stock
price used to set Q4 2019 guidance was $10.20 per share, in line
with the price on September 30, 2019. As a result no cash-based
equity compensation cumulative adjustment has been incorporated
into our guidance.
(e) 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
higher than interest expense due to the timing of interest
payments.
(f) Due to our tax position there is no
difference between the impact on our income and cash flows.
(g) Amount reflects the sensitivity
assuming no hedged barrels. We have downside price protection on
44% of our Q4 2019 oil production, at a weighted-average Brent
floor price of $76 per barrel until Brent falls below $60, when we
receive Brent plus $16 per barrel.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20191031005903/en/
Scott Espenshade (Investor Relations) 818-661-6010
Scott.Espenshade@crc.com
Margita Thompson (Media) 818-661-6005
Margita.Thompson@crc.com
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