California Resources Corporation (NYSE:CRC), an independent
California-based oil and gas exploration and production company,
today reported a net loss of $77 million or $1.83 per diluted share
for the fourth quarter of 2016. For the full year of 2016 net
income was $279 million or $6.76 per diluted share, compared with a
net loss of $3.6 billion or $92.79 per diluted share for the same
period of 2015. Additionally, CRC announced 2016 reserves of 568
million barrels of oil equivalent (BOE) and 2017 capital investment
plans of $300 million.
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Adjusted EBITDAX1 for the fourth quarter and the full year of
2016 was $168 million and $616 million, respectively, compared with
$226 million and $906 million for the fourth quarter and the full
year of 2015. CRC had annual operating cash flow of $130 million in
2016 and capital investments of $75 million. This financial
discipline allowed CRC to generate $49 million of free cash flow
after working capital1.
Highlights Include:
- Received sixth bank amendment removing
capital investment limitations and allowing additional joint
ventures, among other changes
- Initial 2017 capital investment plan of
$300 million
- 2016 capital investment of $75 million
with only $31 million of drilling and workover capital
- Quarterly production of 135,000 BOE per
day
- A 2.2% sequential decline
- A 10% year-over-year decline, excluding
PSC effects
- Annual production of 140,000 BOE per
day
- Annual production costs down 16% from
prior year
- Annual operating cash flow of $130
million
- 2016 Annual free cash flow2 after
working capital of $49 million
- 2016 Organic reserve replacement ratio
of 71% with minimal drilling and workover capital
- 2016 Adjusted Organic F&D costs of
$3.42 per BOE3 excluding price adjustments
1,2 For explanations of how we calculate and use Adjusted Net
Loss (non-GAAP) and Adjusted EBITDAX (non-GAAP) and reconciliations
of net income / (loss) (GAAP) and net cash provided by operating
activities (GAAP) to Adjusted EBITDAX and free cash flow after
working capital (non-GAAP), please see Attachments 2 and 3.3 See
calculation of F&D on attachment 4.
Todd Stevens, President and Chief Executive Officer, said, "We
are pleased with our 2016 performance as we strengthened our
balance sheet, continued to live within our cash flows, managed our
base production to a minimal decline and increased our probable and
possible reserves significantly. These achievements reflect the
diligence of our team as well as the resiliency of our operations
and complementary infrastructure.
"Our planned 2017 capital budget of about $300 million should
allow us to increase activity, enhance margins and return to a
growth profile beginning in the second half of the year.
Additionally, we expect to further expand our actionable inventory.
We are pleased to have received our sixth bank amendment which
removed capital investment limitations. We will continue to align
our investments with our cash flow."
Fourth Quarter Results
For the fourth quarter of 2016, CRC reported a net loss of $77
million or $1.83 per diluted share, compared with a net loss of
$3.3 billion or $85.47 per diluted share for the same period of
2015. The 2016 quarter reflected slightly lower realized oil prices
including the effect of settled hedges. Compared to the prior year
period, the 2016 quarter also reflected higher realized NGL and
natural gas prices and lower costs, partially offset by lower
volumes, while the 2015 quarter included a non-cash, after-tax
impairment charge of $2.9 billion ($4.9 billion pre-tax) and other
items. The fourth quarter 2016 adjusted net loss was $74 million or
$1.76 per diluted share, compared with an adjusted net loss of $77
million or $2.01 per diluted share for the same period of 2015. The
2016 adjusted net loss excluded $40 million of non-cash derivative
losses on outstanding hedges, $12 million of net gains on the early
extinguishment of certain of the Company's notes, and $25 million
of net gains from other miscellaneous, infrequent items. The 2015
adjusted net loss excluded the impairment charge described above, a
$294 million valuation allowance for deferred assets and other
after-tax write-offs of $36 million largely reflecting the impact
of lower prices on other assets.
Adjusted EBITDAX for the fourth quarter of 2016 was $168
million, compared to $226 million for the same period of 2015.
Total daily production volumes averaged 135,000 barrels of oil
equivalent (BOE) for the fourth quarter of 2016, compared with
155,000 BOE for the fourth quarter of 2015, a decrease of less than
13 percent, which is within CRC's estimated base production decline
range. This decrease included effects of production sharing
contracts (or "PSC") of 4,000 BOE per day. Excluding this PSC
effect, the year-over-year quarterly decline would have been 10
percent. The fourth quarter 2016 production decline continued to
reflect management's decision to withhold development capital and
to selectively defer workover and downhole maintenance activity in
the early part of the year. Due to the improved commodity price
environment in the second half of the year, the Company began
increasing its activity levels, particularly in the fourth quarter,
resulting in lower quarterly sequential declines. In the fourth
quarter of 2016, realized crude oil prices, including the effect of
settled hedges, decreased $0.40 per barrel to $45.48 per barrel
from $45.88 per barrel in the prior year comparable quarter.
Settled hedges reduced realized crude oil prices by $1.12 per
barrel in the fourth quarter of 2016, while increasing the fourth
quarter 2015 realized prices by $6.47 per barrel. Realized NGL
prices increased 48 percent to $28.99 per barrel from $19.56 per
barrel in the fourth quarter of 2015. Realized natural gas prices
increased 14 percent to $2.79 per thousand cubic feet (Mcf),
compared with $2.44 per Mcf in the same period of 2015. The fourth
quarter 2015 realized natural gas prices included $0.16 per Mcf
from settled hedges.
Production costs for the fourth quarter of 2016 were $217
million or $17.50 per BOE, compared with $221 million or $15.51 per
BOE for the fourth quarter of 2015, a 2-percent reduction on an
absolute dollar basis. The decrease was driven by well servicing
efficiencies and lower energy costs. The fourth quarter of 2016
also reflected $10 million in higher compensation costs than the
comparable 2015 quarter. General and administrative (G&A)
expenses were $62 million or $5.00 per BOE for the fourth quarter
of 2016, compared with $64 million or $4.48 per BOE for the fourth
quarter of 2015. The decrease in total G&A expenses reflects
employee and contractor cost-reduction initiatives offset by higher
employee compensation resulting from a significant increase in the
stock price in the fourth quarter of 2016. Adjusted G&A
expenses for the fourth quarter of 2016 were $61 million or $4.92
per BOE, compared with $69 million or $4.80 per BOE for the fourth
quarter of 2015. Taxes other than on income of $26 million for the
fourth quarter of 2016 were $4 million lower than the same period
of 2015. Exploration expenses of $10 million for the fourth quarter
of 2016 were $3 million higher than the same period of 2015.
Capital investment in the fourth quarter of 2016 totaled $31
million, of which $20 million was directed to drilling and capital
workovers.
Full Year 2016 Results
For the full year of 2016, CRC reported net income of $279
million or $6.76 per diluted share, compared with a net loss of
$3.6 billion or $92.79 per diluted share in 2015. The 2016 income
reflected the net gains from the early extinguishment of the
Company's notes and divestiture of assets as well as lower costs,
partially offset by lower oil and natural gas prices and volumes
and non-cash derivative losses on outstanding hedges, while 2015
also included the fourth-quarter impairment charge and other items.
The 2016 adjusted net loss was $317 million or $7.85 per diluted
share, compared with an adjusted net loss of $311 million or $8.12
per diluted share for 2015. The 2016 adjusted net loss excluded
$805 million of net gains on the early extinguishment of the
Company's notes, $283 million of non-cash derivative losses on
outstanding hedges, a $63 million benefit from a deferred tax
valuation allowance adjustment, a $20 million charge resulting from
employee reductions that were made during the year, a $30 million
gain from asset divestitures, a $12 million write-off of deferred
financing costs related to the retirement of the Company's notes
and $13 million net gains from other miscellaneous, infrequent
charges. The 2015 adjusted net loss excluded a non-cash, after-tax
impairment charge of $2.9 billion ($4.9 billion pre-tax), a $294
million valuation allowance for deferred assets, $52 million of
non-cash derivative gains, a $71 million charge reflecting the
effect of prices on other assets, $67 million of severance and
early retirement costs, and $19 million net from other infrequent
net charges and related tax adjustments.
Adjusted EBITDAX for the full year of 2016 was $616 million,
compared to $906 million in the prior-year period.
Total daily production volumes averaged 140,000 BOE for the full
year of 2016, compared with 160,000 BOE for the full year of 2015,
a 12.5-percent decrease which is within CRC's estimated base
production decline range. Excluding the PSC effects, the annual
decline would have been under 12 percent. CRC's year-over-year
average oil production was 91,000 barrels per day for the full year
of 2016, a decrease of under 13 percent, or 13,000 barrels per day,
compared with the same period of 2015. NGL production decreased by
11 percent to 16,000 barrels per day and natural gas production
decreased by 14 percent to 197 million cubic feet (MMcf) per
day.
Realized crude oil prices, including the effect of settled
hedges, decreased 15 percent to $42.01 per barrel for 2016 from
$49.19 per barrel in 2015. Hedges contributed $2.29 per barrel to
realized crude oil prices for 2016, compared with $2.04 for the
same period of 2015. Realized NGL prices increased 14 percent to
$22.39 per barrel for 2016 from $19.62 per barrel in 2015. Realized
natural gas prices decreased 14 percent to $2.28 per Mcf for 2016,
compared with $2.66 per Mcf in the same period of 2015.
Production costs for 2016 were $800 million or $15.61 per BOE,
compared with $951 million or $16.30 per BOE for the same period in
2015, a 16-percent reduction on an absolute dollar basis. The
decrease reflected cost reductions throughout CRC's operations,
particularly in well servicing efficiency, lower personnel costs,
lower energy use and lower natural gas prices, as well as lower
workover and downhole maintenance activity in 2016. G&A
expenses were $248 million or $4.84 per BOE for the full year of
2016, compared with $354 million or $6.07 per BOE for the same
period of 2015, reflecting employee and contractor cost-reduction
initiatives and greater severance and early retirement costs
included in the prior-year period. Adjusted G&A expenses were
$228 million or $4.45 per BOE for the full year of 2016, compared
with $287 million or $4.92 per BOE for the same period of 2015.
Adjusted G&A expenses for both years excluded severance and
early retirement. Exploration expenses of $23 million for the full
year of 2016 were $13 million lower than the same period of 2015.
Taxes other than on income were $144 million for 2016, compared to
$180 million for 2015. The decrease was largely due to a reduction
in property taxes.
Consistent with our operating tenet of living within cash flow,
the Company generated $130 million of operating cash flow and free
cash flow after capital of $49 million for the full year of
2016.
2016 Proved Reserves and PV-10
Value
CRC’s proved reserves estimates for the year ended December 31,
2016, as audited by Ryder Scott, were 568 million BOE, consisting
of 72 percent oil and 71 percent proved developed volumes. The
Company achieved a total organic reserves replacement ratio
(RRR)(4) of 71 percent of 2016 production, excluding price
adjustments. Price-related adjustments reduced overall reserves by
60 million BOE. Volumes that have been removed from the reserves
base due to lower prices are expected to return to CRC's proved
base at higher prices of crude oil.
Summary of Changes in Proved Reserves (Million BOE)
Balance at December 31, 2015 644 Revision of Previous
Estimates (Performance-Related) 13 Extensions and
Discoveries 20 Improved Recovery 3
Divestiture of Proved Reserves (1) Price-Related
Revisions (60) Production (51) Balance at December
31, 2016 568* 2016 Organic F&D
cost, excluding price adjustments(5) $3.42
*Calculated using the first-day-of-the-month twelve-month
average Brent oil price of $42.90 per barrel and Henry Hub price of
$2.48 per million British Thermal units (BTU) for natural gas,
before adjustments for gravity, quality and transportation costs,
in accordance with Securities and Exchange Commission (SEC)
guidelines.4,5 See calculation of RRR and F&D on attachment
4.
The present value of CRC's proved reserves as of December 31,
2016 was approximately $2.8 billion, on a pre-tax basis, discounted
at 10 percent (PV-10)(6). The reduction from the prior year amount
of $5.1 billion, resulted from a 23-percent and 4-percent decrease
in crude oil prices and natural gas prices, respectively. The
effect of price decreases was partially offset by reserves
additions, cost reductions and efficiencies identified in the
Company's life-of-field plans. Utilizing current costs, a flat $55
Brent crude oil price deck and $3.30/Mcf Henry Hub natural gas
price, which is similar to the 2015 SEC pricing and the current
strip prices, CRC's proved reserves would be approximately 686
million barrels. Using these same assumptions, the PV-10 would be
nearly $5.4 billion for proved reserves and $9.7 billion for
proved, probable and possible reserves.
6 PV-10 is a non-GAAP financial measure. For a reconciliation to
the GAAP standardized measure of discounted future net cash flows,
see attachment 4.
Hedging Update
CRC continues to opportunistically add hedges to protect its
cash flow, margins and capital program and to maintain liquidity.
For example, currently we have hedges in place covering over 45% of
our projected first quarter 2017 oil production. See attachment 11
for more details.
Operational Update and 2017 Capital
Investment Plan
CRC operated two drilling rigs at year end 2016 with one in the
San Joaquin basin and one in the Los Angeles basin. In the fourth
quarter, CRC drilled 4 waterflood wells and 17 steamflood wells. By
the end of the first quarter of 2017, we anticipate having four
rigs running (three in the San Joaquin basin and one in the Los
Angeles basin).
Consistent with prior years, CRC expects to align our capital
investment with our operational cash flow, and adjust our capital
plan accordingly. Based on the current market conditions, CRC will
begin the year with a capital investment plan of $300 million,
consisting of approximately $150 million for drilling and
completions, $50 million for capital work-overs, $50 million for
facilities, $25 million for exploration and $25 million primarily
for mechanical integrity projects. Our 2017 development program
will focus primarily on our core fields- Elk Hills, Wilmington,
Kern Front, Buena Vista, and the delineation of Kettleman North
Dome. We have developed a dynamic plan which can be scaled up or
down depending on the price environment. For 2017, we have action
plans that allow us to reduce our capital investment to under $100
million or increase it to as high as $500 million based on
conditions during the year. Going forward, we will continue to
focus on identifying, evaluating and pursuing value creation
opportunities that strengthen our balance sheet and reduce our
financial leverage.
CRC Analyst Day and Site
Tour
We are pleased to announce that CRC is hosting a 2017 Analyst
Day and Site Tours in the Bakersfield and Long Beach areas in
California on March 22-23. Due to the length of the event,
logistical considerations and safety requirements, space will be
limited. We will be webcasting the formal presentations and will
post them to CRC's investor relations page on our website at
www.crc.com. The event will be archived for play later on the day
of the presentations.
Conference Call Details
To participate in today’s conference call, 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/10097714. 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 Investor
Relations at 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
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 our
expected results of operations, liquidity, cash flows and business
prospects. Such statements include those regarding our expectations
as to our 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
VCI
- budgets and maintenance capital
requirements
- reserves
Actual results may differ from anticipated results, sometimes
materially, and reported results should not be considered an
indication of future performance. While we believe assumptions or
bases underlying our expectations are reasonable and make them in
good faith, they almost always vary from actual results, sometimes
materially. Factors (but not necessarily all the factors) that
could cause results to differ include:
- commodity price changes
- debt limitations on our financial
flexibility
- insufficient cash flow to fund planned
investment
- 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 our products
- 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
- 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 constraints, natural disasters,
labor difficulties, cyber attacks or other catastrophic events
- factors discussed in “Risk Factors” in
our Annual Report on Form 10-K available on our 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 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.
We have provided internally generated estimates of PV-10 for
proved reserves and aggregated proved, probable and possible
reserves (“3P Reserves”) as of December 31, 2016 in this
presentation, with each category of reserves estimated in
accordance with SEC guidelines and definitions, though we have not
reported all such estimates to the SEC. As used in this
presentation:
Probable reserves. We use deterministic
methods to estimate probable reserve quantities, and when
deterministic methods are used, it is as likely as not that actual
remaining quantities recovered will exceed the sum of estimated
proved plus probable reserves.
Possible reserves. We use deterministic
methods to estimate possible reserve quantities, and when
deterministic methods are used to estimate possible reserve
quantities, the total quantities ultimately recovered from a
project have a low probability of exceeding proved plus probable
plus possible reserves.
The SEC prohibits companies from aggregating proved, probable
and possible reserves estimated using deterministic estimation
methods in filings with the SEC due to the different levels of
certainty associated with each reserve category.
Actual quantities that may be ultimately recovered from our
interests may differ substantially from the estimates in this
release. Factors affecting ultimate recovery include the scope of
our ongoing drilling and workover program, which will be directly
affected by commodity prices, the availability of capital,
regulatory approvals, drilling and production costs, availability
of drilling services and equipment, drilling results, lease
expirations, transportation constraints and other factors; actual
drilling results, which may be affected by geological, mechanical
and other factors that determine recovery rates; and budgets based
upon our future evaluation of risk, returns and the availability of
capital.
Attachment 1 SUMMARY OF RESULTS
Fourth Quarter Twelve Months ($ and shares in
millions, except per share amounts)
2016 2015
2016
2015
Statement of
Operations Data:
Revenues and Other Oil and gas net sales
$ 464
$ 447
$ 1,621 $ 2,134 Net derivative (losses) gains
(49 ) 83
(206 ) 133 Other revenue
37 36
132 136 Total
revenues and other
452 566
1,547
2,403
Costs and Other Production costs
217 221
800 951 General and administrative expenses
62 64
248 354 Depreciation, depletion and
amortization
137 247
559 1,004 Asset impairments
— 4,852
— 4,852 Taxes other than on income
26
30
144 180 Exploration expense
10 7
23 36
Other expenses, net
3 94
79 168
Total costs and other
455 5,515
1,853 7,545
Operating Loss
(3 ) (4,949 )
(306 ) (5,142 )
Non-Operating (Loss) Income Interest and debt expense, net
(85 ) (82 )
(328 ) (326 ) Net gains on
early extinguishment of debt
12 20
805 20 Other
non-operating (expense) income
(1 ) (28 )
30 (28 )
(Loss) Income Before Income
Taxes (77 ) (5,039 )
201 (5,476 ) Income
tax benefit
— 1,757
78 1,922
Net (Loss) Income $ (77 )
$ (3,282 )
$ 279 $ (3,554 ) EPS -
diluted
$ (1.83 ) $ (85.47 )
$
6.76 $ (92.79 ) Adjusted Net Loss
$ (74
) $ (77 )
$ (317 ) $ (311 ) Adjusted
EPS - diluted
$ (1.76 ) $ (2.01 )
$
(7.85 ) $ (8.12 ) Weighted average diluted
shares outstanding
42.1 38.4
40.4 38.3
Adjusted EBITDAX
$ 168 $ 226
$ 616 $
906 Effective tax rate
0 % 35 %
(39 )%
35 %
Cash Flow Data: Net cash (used)
provided by operating activities
$ (15 ) $ (9
)
$ 130 $ 403 Net cash used by investing activities
$ (30 ) $ (215 )
$ (61 )
$ (757 ) Net cash (used) provided by financing activities
$
47 $ 232
$ (69 ) $ 352
Balance Sheet Data: December 31,
December 31,
2016 2015 Total current assets
$
425 $ 438 Property, plant and equipment, net
$
5,885 $ 6,312 Total current liabilities
$ 726
$ 605 Long-term debt, principal amount
$ 5,168 $
6,043 Total equity
$ (557 ) $ (916 )
Outstanding shares as of
42.5 38.8
Attachment
2 NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
Our results of operations can include the effects of unusual and
infrequent transactions and events affecting earnings that vary
widely and unpredictably in nature, timing, amount and frequency.
Therefore, management uses a measure called "adjusted net income /
(loss)" and a measure it calls "adjusted general and administrative
expenses" which exclude those items. These non-GAAP measures are
not meant to disassociate items from management's performance, but
rather are 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) and adjusted
general and administrative expenses are not considered to be
alternatives to net income / (loss) and general and administrative
expenses reported in accordance with GAAP. The following
table presents a reconciliation of the GAAP financial measure of
net (loss) income to the non-GAAP financial measure of adjusted net
(loss) income: Fourth Quarter Twelve Months ($ millions,
except per share amounts)
2016 2015
2016 2015
Net (loss) income
$ (77 ) $ (3,282 )
$
279 $ (3,554 ) Unusual and infrequent items: Asset
impairments
— 4,852
— 4,852 Write-down of certain
assets
— 71
— 71 Non-cash derivative losses (gains)
40 (19 )
283 (52 ) Severance, early retirement and
other costs
1 (5 )
20 67 Refunds, plant turnaround
charges and other
(27 ) 5
(13 ) 11 Net
gains on early extinguishment of debt
(12 ) (20 )
(805 ) (20 ) Debt issuance costs
— 28
—
28 Loss (gain) from asset divestitures
1 —
(30 ) — Adjusted income items before interest
and taxes
3 4,912
(545 ) 4,957 Deferred
debt issuance costs write-off
— —
12 — Adjustments
for valuation allowance on deferred tax assets
— 294
(63 ) (a) 294 Tax effects of these items and related
adjustments
— (2,001 )
— (2,008 ) Total
$ 3 $ 3,205
$ (596
) $ 3,243 Adjusted net loss
$ (74
) $ (77 )
$ (317 ) $ (311 ) Net
(loss) income per diluted share
$ (1.83 ) $
(85.47 )
$ 6.76 $ (92.79 ) Adjusted net loss per
diluted share
$ (1.76 ) $ (2.01 )
$
(7.85 ) $ (8.12 ) (a) Amount represents the
out-of-period portion of the valuation allowance reversal.
DERIVATIVES GAINS AND LOSSES
Fourth Quarter Twelve Months ($ millions)
2016 2015
2016 2015 Non-cash derivative losses (gains)
$
40 $ (19 )
$ 283 $ (52 ) Payments (proceeds)
from settled derivatives
9 (64 )
(77 )
(81 ) Net derivative losses (gains)
$ 49 $ (83
)
$ 206 $ (133 )
FREE CASH FLOW Fourth
Quarter Twelve Months ($ millions)
2016 2015
2016
2015 Operating cash flow
$ (15 ) $ (9 )
$ 130 $ 403 Capital investment
(31 )
(78 )
(75 ) (401 ) Changes in capital accruals
(1 ) (3 )
(6 ) (205 ) Free cash flow
(after working capital)
$ (47 ) $ (90 )
$ 49 $ (203 )
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES Fourth
Quarter Twelve Months ($ millions)
2016 2015
2016
2015 General and administrative expenses
$ 62
$ 64
$ 248 $ 354 Severance, early retirement and
other costs
(1 ) 5
(20 ) (67 )
Adjusted general and administrative expenses
$ 61
$ 69
$ 228 $ 287
Attachment 3 NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS We define adjusted EBITDAX as earnings before
interest expense; income taxes; depreciation, depletion and
amortization; exploration expense; and other unusual and infrequent
items. Our management believes 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 U.S. generally
accepted accounting principles (GAAP). This measure is a material
component of certain of our financial covenants under our
first-lien, first-out credit facilities 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. The following tables present a
reconciliation of the GAAP financial measures of net (loss) /
income and net cash (used) / provided by operating activities to
the non-GAAP financial measure of adjusted EBITDAX:
Fourth Quarter Twelve Months ($ millions)
2016
2015
2016 2015 Net (loss) income
$ (77
) $ (3,282 )
$ 279 $ (3,554 ) Interest and
debt expense
85 82
328 326 Income tax benefit
— (1,757 )
(78 ) (1,922 ) Depreciation,
depletion and amortization
137 247
559 1,004
Exploration expense
10 7
23 36 Adjusted income items
before interest and taxes(a)
3 4,912
(545 )
4,957 Other items
10 17
50 59
Adjusted EBITDAX
168 226
616 906 Net
cash (used) provided by operating activities
$ (15
) $ (9 )
$ 130 $ 403 Cash Interest
140
111
384 359 Exploration expenditures
7 7
20 27
Other changes in operating assets and liabilities
63 112
95 106 Refunds, plant turnaround charges and other
(27 ) 5
(13 ) 11 Adjusted
EBITDAX
168 226
616 906 (a) See Attachment 2.
Attachment 4 NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS The
following table presents a reconciliation of the non-GAAP financial
measure of PV-10 to the GAAP financial measure of standardized
measure of discounted future net cash flows:
PV-10 and
Standardized Measure ($ millions) 2016 PV-10 of proved
reserves (1)
$ 2,848 Present value of future income
taxes discounted at 10%
(181 ) Standardized
measure of discounted future net cash flows
$ 2,667
(1) PV-10 is a non-GAAP financial measure and
represents the year-end present value of estimated future cash
inflows from proved oil and natural gas reserves, less future
development and production costs, discounted at 10% per annum to
reflect the timing of future cash flows 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 construed as 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 an asset 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.
Organic Reserve Replacement Ratio
(2) 2016 Proved reserves added - MMBOE Extensions and
Discovery
20 Improved Recovery
3 Revisions related to
performance
13
Total (A)
36 Production in 2016 - MMBOE (B)
51 Organic Reserves Replacement Ratio (A)/(B)
71
% (2) The organic reserves replacement ratio is
calculated for a specified period using the proved oil-equivalent
additions from extensions and discoveries, improved recovery, and
performance-related provisions, divided by oil-equivalent
production. Approximately 89% of the additions for 2016 are proved
undeveloped. There is no guarantee that historical sources of
reserves additions will continue as many factors could cause
unforeseen results, including geology, government regulations and
permits, commodity prices, the availability of capital, the
effectiveness of development plans and other factors that affect
reserves additions and are partially or fully outside management's
control. Management uses this measure to gauge results of its
capital allocation.
Organic Finding and
Development Costs(3) 2016 Organic costs incurred
- in millions (A)
$
123
(4)
Proved Reserves Added - MMBOE (B)
36
(5)
Organic Finding and Development Costs - $/BOE (A)/(B)
$
3.42 (3) We calculate organic finding and development
costs by dividing the costs incurred for the year from the capital
program (including development, including asset retirement
obligations, and exploration costs, but excluding acquisitions) by
the amount of oil-equivalent proved reserves added in the same year
from improved recovery, extensions and discoveries and
performance-related revisions (excluding acquisitions and
price-related revisions). We believe that reporting our finding and
development costs can aid investors in their evaluation of our
ability to add proved reserves at a reasonable cost but is not a
substitute for GAAP disclosures. Various factors, including timing
differences and effects of commodity price changes, can cause
finding and development costs to reflect costs associated with
particular reserves imprecisely. For example, we will need to make
more investments in order to develop the proved undeveloped
reserves added during the year and any future revisions may change
the actual measure from that presented above. In addition, part of
the 2016 costs were incurred to convert proved undeveloped reserves
from prior years to proved developed reserves. Our calculations of
finding and development costs may not be comparable to similar
measures provided by other companies. We have not estimated future
costs expected for the reserves added or removed costs related to
reserves added in prior periods. (4) Includes development and
exploration costs, as well as asset retirement obligations. (5)
Includes performance revisions.
Attachment 5
ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS ($ millions)
2015 4th Quarter Adjusted Net Loss $
(77 ) Price - Oil (2 ) Price - NGLs 15 Price -
Natural Gas 7 Volume (47 ) Production cost rate (4 ) DD&A rate
91 Exploration expense (3 ) Interest expense (3 ) Adjusted general
& administrative expenses 8 Income tax (50 ) All Others (9 )
2016 4th Quarter Adjusted Net Loss $
(74 ) 2015 Twelve Month Adjusted Net
Loss $ (311 ) Price - Oil (283 )
Price - NGLs 19 Price - Natural Gas (31 ) Volume (116 ) Production
cost rate 122 DD&A rate 376 Exploration expense 13 Interest
expense 10 Adjusted general & administrative expenses 59 Income
tax (193 ) All Others 18
2016 Twelve Month Adjusted Net
Loss $ (317 )
Attachment 6
CAPITAL INVESTMENTS Fourth Quarter Twelve Months ($
millions)
2016 2015
2016 2015 Capital Investments:
Conventional
$ 22 $ 62
$ 41 $ 328
Unconventional
6 8
12 25 Exploration
1 —
1 17 Other (a)
2 8
21 31
$ 31 $ 78
$ 75
$ 401 (a) Twelve months of 2016
includes $19 million of capital incurred for the planned turnaround
at the Elk Hills Power Plant, of which payment of $10 million is
deferred to future periods.
Attachment 7 PRODUCTION STATISTICS
Fourth Quarter Twelve Months
Net
Oil, NGLs and Natural Gas Production Per Day 2016 2015
2016 2015
Oil (MBbl/d) San Joaquin Basin
55 61
57 64 Los Angeles Basin
27 35
29
34 Ventura Basin
5 6
5 6 Sacramento Basin
—
—
— — Total
87 102
91 104
NGLs (MBbl/d) San Joaquin Basin
14 17
15 17 Los Angeles Basin
— —
— — Ventura Basin
1 1
1 1 Sacramento Basin
— —
— — Total
15 18
16 18
Natural
Gas (MMcf/d) San Joaquin Basin
152 161
150 172
Los Angeles Basin
1 2
3 2 Ventura Basin
8 9
8 11 Sacramento Basin
34 40
36
44 Total
195 212
197 229
Total Barrels of Oil Equivalent (MBoe/d) (a)
135 155
140 160 (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. The price of natural gas on a barrel
of oil equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a
number of years. For example, for the year ended December 31, 2016,
the average prices of Brent oil and NYMEX natural gas were $45.04
per Bbl and $2.42 per MMBtu, respectively, resulting in an
oil-to-gas price ratio of approximately 19 to 1.
Attachment 8 PRICE STATISTICS Fourth Quarter
Twelve Months
2016 2015
2016 2015
Realized
Prices Oil with hedge ($/Bbl)
$ 45.48 $ 45.88
$ 42.01 $ 49.19 Oil without hedge ($/Bbl)
$
46.60 $ 39.41
$ 39.72 $ 47.15 NGLs
($/Bbl)
$ 28.99 $ 19.56
$ 22.39 $ 19.62
Natural gas with hedge ($/Mcf)
$ 2.79 $ 2.44
$ 2.28 $ 2.66 Natural gas without hedge ($/Mcf)
$ 2.79 $ 2.28
$ 2.28 $ 2.61
Index Prices Brent oil ($/Bbl)
$ 51.13 $ 44.71
$ 45.04 $ 53.64 WTI oil ($/Bbl)
$ 49.29
$ 42.18
$ 43.32 $ 48.80 NYMEX gas ($/MMBtu)
$
2.95 $ 2.44
$ 2.42 $ 2.75
Realized
Prices as Percentage of Index Prices Oil with hedge as a
percentage of Brent
89 % 103 %
93 % 92
% Oil without hedge as a percentage of Brent
91 % 88
%
88 % 88 % Oil with hedge as a percentage of
WTI
92 % 109 %
97 % 101 % Oil without
hedge as a percentage of WTI
95 % 93 %
92
% 97 % NGLs as a percentage of Brent
57
% 44 %
50 % 37 % NGLs as a percentage of WTI
59 % 46 %
52 % 40 % Natural gas
with hedge as a percentage of NYMEX
95 % 100 %
94 % 97 % Natural gas without hedge as a percentage
of NYMEX
95 % 93 %
94 % 95 %
Attachment 9
2017 FIRST QUARTER GUIDANCE Anticipated
Realizations Against the Prevailing Index Prices for Q1 2017
(a) Oil 88% to 92% of Brent NGLs 50% to 55% of Brent Natural
Gas 90% to 94% of NYMEX
2017 First Quarter Production,
Capital and Income Statement Guidance Production 128 to 133
MBOE per day Capital $60 million to $70 million Production costs
$18.10 to $18.60 per BOE Adjusted general and administrative
expenses $5.35 to $5.65 per BOE Depreciation, depletion and
amortization $11.65 to $11.95 per BOE Taxes other than on income
$31 million to $35 million Exploration expense $5 million to $9
million Interest expense
(b) $81 million to $85 million Cash
Interest
(b) $52 million to $56 million Income tax expense
rate 0% Cash tax rate 0% On Income On Cash
Pre-tax
First Quarter Price Sensitivities $1 change in Brent index -
Oil (at price above $56.00) (c) $3.5 million $3.5 million $1 change
in Brent index - NGLs $0.8 million $0.8 million $0.50 change in
NYMEX - Gas $3.2 million $3.2 million
First
Quarter Volumes Sensitivities $1 change in the Brent index (d)
200 Bbl/d (a) Realizations exclude hedge effects. (b)
Interest expense includes the amortization of 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. (c) At a Brent index price between $49.00 and
$56.00 the sensitivity goes up to $4.4 million. (d) Reflects the
effect of production sharing type contracts in our Wilmington field
operations.
Attachment
10 FULL YEAR DRILLING ACTIVITY San Joaquin Los
Angeles Ventura Sacramento Wells Drilled
(Net) Basin Basin Basin Basin
Total Development Wells Primary — — — — —
Waterflood 3 5 — — 8 Steamflood 34 — — — 34 Unconventional — — — —
— Total 37 5 — — 42
Exploration Wells Primary — — — —
— Waterflood — — — — — Steamflood — — — — — Unconventional — — — —
— Total — — — — —
Total
Wells 37 5 — — 42
Development Drilling Capital
($ millions)
$7 $6 $— $— $13
Attachment 11 HEDGING ACTIVITY Q1
2017 Q2 2017 Q3 2017 Q4 2017 Q1
2018 Q2-Q4 2018 Crude Oil Calls: Barrels per day
12,100 5,000 10,000 15,000 15,600 15,000 Weighted-average price per
barrel $ 56.37 $ 55.05 $ 56.15 $ 56.12 $ 58.77 $ 58.83 Puts:
Barrels per day 22,100 20,000 17,000 10,000 Weighted-average price
per barrel $ 49.10 $ 50.25 $ 50.88 $ 48.00 Swaps: Barrels
per day 20,000 20,000 20,000 20,000 Weighted-average price per
barrel $ 53.98 $ 53.98 $ 53.98 $ 53.98 The second through
fourth quarter 2017 crude oil swaps grant the counterparty a
quarterly option to increase volumes by up to 10,000 barrels per
day for that quarter at a weighted-average Brent price of $55.46.
The counterparty also has an option to increase volumes by up to
5,000 barrels per day for the second half of the year at a
weighted-average Brent price of $61.43.
Attachment 12
RESERVES San
Joaquin Los Angeles Ventura Sacramento
As of December
31, 2016
Basin Basin Basin
Basin Total Oil Reserves (in millions of
barrels) Proved Developed Reserves 177 82 20 — 279 Proved
Undeveloped Reserves 110 16 4 — 130 Total 287 98 24 — 409
NGLs Reserves (in millions of barrels) Proved Developed
Reserves 42 — 2 — 44 Proved Undeveloped Reserves 11 — — — 11 Total
53 — 2 — 55
Natural Gas Reserves (in billions of cubic
feet) Proved Developed Reserves 410 7 15 68 500 Proved
Undeveloped Reserves 126 — — — 126 Total 536 7 15 68 626
Total Reserves (in millions of barrels of oil equivalent)*
Proved Developed Reserves 287 83 25 11 406 Proved Undeveloped
Reserves 142 16 4 — 162 Total 429 99 29 11 568
*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. The price of natural gas on a barrel
of oil equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a
number of years. For example, in 2016, the average prices of Brent
oil and NYMEX natural gas were $45.04 per Bbl and $2.42 per MMBtu,
respectively, resulting in an oil-to-gas price ratio of
approximately 19 to 1.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20170216006267/en/
California Resources CorporationScott Espenshade (Investor
Relations)818-661-6010Scott.Espenshade@crc.comorMargita
Thompson
(Media)818-661-6005Margita.Thompson@crc.com
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