Exhibit 99.1
News release via Canada NewsWire, Calgary 403-269-7605
Attention Business/Financial Editors:
OPTI Canada Announces Third Quarter 2009 Results
TSX: OPC
CALGARY, Oct. 28 /CNW/ - OPTI Canada Inc. (OPTI) announced today the
Company's financial and operating results for the quarter ended September 30,
2009.
The Long Lake Project (the Project) is the first to use OPTI's integrated
OrCrude(TM) process. Our proprietary process is designed to substantially
reduce operating costs compared to other oil sands projects while producing a
high quality, sweet synthetic crude oil.
"We had a good quarter operationally. Our objectives in the third quarter
were to complete the planned turnaround and to start-up the final components
of the Upgrader, which are the thermal cracker and the solvent deasphalter.
Both of these objectives were successfully accomplished and the Project is now
positioned to ramp-up with improved PSC(TM) yield and enhanced steam
generation capabilities," said Chris Slubicki, President and Chief Executive
Officer.
<<
FINANCIAL HIGHLIGHTS
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Three months Nine months Year
ended ended ended
September 30, September 30, December 31,
In millions 2009 2009 2008
(as revised)
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Net earnings (loss) $ 12 $ (95) $ (477)(1)
Total oil sands expenditures(2) 31 128 706
Working capital (deficiency) 10 10 (25)
Shareholders' equity $ 1,523 $ 1,523 $ 1,471
Common shares outstanding
(basic)(3) 282 282 196
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Notes:
(1) Includes $369 million pre-tax asset impairment provision related to
working interest sale to Nexen.
(2) Capital expenditures related to Phase 1 and future phase development.
Capitalized interest, hedging gains/losses and non-cash additions or
charges are excluded.
(3) Common shares outstanding at September 30, 2009 after giving effect
to the exercise of stock options would be approximately 287 million
common shares.
>>
OPERATIONAL UPDATE
Several important operational milestones were achieved in the third
quarter. First, the previously announced turnaround at the Long Lake Project
has been successfully completed, including valve replacement and maintenance
on the water treatment plant intended to optimize steam production and enhance
long-term production capacity. Improved water treatment operation has already
been observed in the short period since restarting the SAGD facilities.
Currently, steam injection is approximately 60,000 bbl/d and, while early in
the ramp-up process, bitumen production has returned to pre-turnaround levels
of approximately 10,000 to 12,000 bbl/d with 39 well pairs on production.
Another milestone was the completion of the steam debottleneck project
that will increase the SAGD steam design capacity to over 230,000 bbl/d. The
debottleneck train will start-up as needed to support SAGD ramp-up.
The final milestone was the successful testing of the solvent deasphalter
and thermal cracking units in the Upgrader prior to the turnaround. These
units will allow the Operator to transition from gasifying vacuum residue,
which contains some lighter parts of the barrel, to gasifying the heaviest
part of the barrel called asphaltenes. Once this transition is complete we
expect PSC(TM) yields to increase to approximately 80%.
Bitumen production in 2009 has been limited by the ability to produce
large amounts of steam consistently and over a sustained period. Bitumen
production in the third quarter was lower than in previous quarters due to the
previously announced intentional reduction of steam injection in order to
address water chemistry issues in advance of the turnaround and downtime
associated with the turnaround itself. As such, gross bitumen production in
the third quarter averaged approximately 8,800 bbl/d (3,000 bbl/d net to
OPTI).
Electric submersible pumps (ESPs) continued to be installed in a number
of SAGD wells, which will allow us to have better pressure control and
ultimately reduce the overall steam to oil ratio (SOR). We currently have
approximately 42 well pairs with ESPs.
We expect that the improvements made to the SAGD facility in 2009 will
result in a significant increase in bitumen production through 2010 and
position the Project to achieve full design rates. We now expect that the
Project will be at or near design rates later than our previous guidance of
late 2010 and intend to gather post-turnaround operating experience in
consultation with the operator prior to providing updated production guidance.
Once the Project reaches full design rates, it is expected to produce 20,000
bbl/d of PSC(TM) net to OPTI for over 40 years.
<<
RESULTS OF OPERATIONS
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
-------------------------------------------------------------------------
Sep 30 June 30 Sep 30 Sep 30 Sep 30
$ millions 2009 2009 2008 2009 2008
(as revised) (as revised)
-------------------------------------------------------------------------
Revenue, net of
royalties $ 38 $ 34 $ 125 $ 101 $ 125
Expenses
Operating expenses 44 39 37 111 37
Diluent and
feedstock
purchases 29 20 89 78 89
Transportation 3 3 2 9 2
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Net field operating
margin (loss) (38) (28) (3) (97) (3)
Corporate expenses
Interest, net 46 42 18 107 14
General and
administrative 2 7 4 15 12
Financing charges 4 1 - 5 1
Realized loss
(gain) on hedging
instruments (5) (11) (4) (40) (8)
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Earnings (loss)
before non-cash
items (85) (67) (21) (184) (22)
Non-cash items
Foreign exchange
translation loss
(gain) (162) (171) 73 (258) 119
Net unrealized
loss (gain) on
hedging
instruments 82 137 (64) 198 (68)
Depletion,
depreciation and
accretion 5 7 6 16 7
Loss on disposal
of assets - 1 - 2 -
Future tax
(recovery) (22) (32) (4) (47) (13)
-------------------------------------------------------------------------
Net earnings (loss) $ 12 $ (9) $ (32) $ (95) $ (67)
-------------------------------------------------------------------------
>>
Comparative amounts for the three and nine months ended September 30,
2008 have been revised to reflect the retroactive adoption of CICA Handbook
section 3064 "Goodwill and Intangible Assets", effective January 1, 2009.
We define our net field operating margin as revenue related to petroleum
products (net of royalties) and power sales minus operating expenses, diluent
and feedstock purchases and transportation costs. See "Non-GAAP Financial
Measures". This net field operating margin was a loss of $38 million during
the three months ended September 30, 2009 as compared with a loss of $28
million in the preceding quarter. Our net field operating loss increased
during the third quarter primarily due to the plant turnaround which resulted
in higher operating expenses and lower Upgrader on-stream time than in the
prior quarter. The Upgrader on-stream factor decreased from 46% in the second
quarter to 15% in the third quarter, and as a result, in the third quarter we
purchased more diluent, which is blended with bitumen to produce Premium
Synthetic Heavy. Most of our SAGD and Upgrader operating costs are fixed,
therefore we expect that rising SAGD volumes and an increasing Upgrader
on-stream factor will lead to improvements in our net field operating margin.
This expected improvement would result from higher PSC(TM) sales and lower
diluent costs.
The results of operations for the nine month period ended September 30,
2009 include SAGD results for the entire period, as well as Upgrader results
from April 1, 2009, the date we determined the Upgrader to be ready for its
intended use for accounting purposes. The results for the nine month periods
ended September 30, 2008 include SAGD results from July 1, 2008, the date we
determined the SAGD facility to be ready for its intended use.
Results related to the Long Lake Project from 2008 are at a working
interest share of 50%, whereas 2009 results are at a 35% working interest
share due to the sale of 15% of our working interest to Nexen, effective
January 1, 2009.
<<
Revenue
-------
>>
For the three months ended September 30, 2009, we earned revenue of $38
million, compared to $34 million in the three months ended June 30, 2009, and
$125 million in the three months ended September 30, 2008. During the third
quarter our share of PSC(TM) sales averaged 800 bbl/day (Q2 2009: 1,700
bbl/day; Q3 2008: nil) at an average price of approximately $74.75/bbl, while
our share of Premium Synthetic Heavy (PSH) averaged 5,600 bbl/day (Q2 2009:
4,400 bbl/day; Q3 2008: 13,200 bbl/day) at an average price of approximately
$62.25/bbl. Compared to the previous quarter, revenue increased due to higher
PSH sales from bitumen blended with diluent, offset by lower PSC(TM) sales as
a result of a lower Upgrader on-stream factor. Revenue earned during the three
months ended September 30, 2008 consisted primarily of PSH sales when bitumen
production averaged 5,200 bbl/day (Q3 2009: 3,000 bbl/day).
During the third quarter we received pricing for PSC(TM) in-line with or
better than other synthetic crude oils. Due to the premium characteristics of
our PSC(TM), we expect to increase the premium we receive relative to other
synthetic crude oils as production, and therefore the availability of marketed
PSC(TM), increases.
In the three months ended September 30, 2009, we had power sales of $1
million representing 36,848 megawatt hours (MWh) (Q2 2009: 17,167 MWh; Q3
2008: 74,737 MWh) of electricity sold at an average price of approximately
$39/MWh, which is consistent with power sales of $1 million in the three
months ended June 30, 2009. In the three months ended September 30, 2008 power
sales were $5 million which was due to higher excess electricity available for
sale and higher market prices.
For the nine months ended September 30, 2009, we earned revenue of $101
million, which was comprised of $83 million PSH sales, $15 million of PSC(TM)
sales and $4 million of power sales, offset by $1 million of royalties. This
compares to revenue of $125 million for the nine month period ending September
30, 2008, which was comprised primarily of PSH and power sales.
<<
Expenses, gains and losses
--------------------------
(x) Operating expenses
>>
For all three and nine month periods, operating expenses were primarily
comprised of natural gas, maintenance, labour and operating materials and
services.
Operating expenses were $44 million for the three months ended September
30, 2009, compared to $39 million in the three months ended June 30, 2009 and
$37 million in the three months ended September 30, 2008. Operating expenses
in the third quarter were higher than the second quarter of 2009 due to
maintenance work conducted as part of the turnaround in September. There were
no Upgrader related operating expenses in the third quarter of 2008; these
costs were capitalized as the Upgrader was not considered to be ready for its
intended use.
Operating expenses were $111 million for the nine months ended September
30, 2009 compared to $37 million for the corresponding period of 2008.
Operating expenses in 2009 include SAGD results for the entire period, as well
as Upgrader results from April 1, 2009, whereas operating expenses in 2008
only include SAGD results from July 1, 2008.
(x) Diluent and feedstock purchases
Diluent and feedstock purchases were $29 million for the three months
ended September 30, 2009, compared to $20 million in the three months ended
June 30, 2009 and $89 million in the three months ended September 30, 2008.
Third quarter 2009 diluent purchases increased from the second quarter of 2009
due to a lower on-stream factor for the Upgrader, requiring increased diluent
to blend with bitumen to make PSH. In the third quarter of 2009 we purchased
approximately 3,000 bbl/day of diluent at an average price of $73/bbl,
compared to second quarter 2009 purchases of 1,900 bbl/day of diluent at an
average price of $69/bbl. Diluent purchases in the third quarter of 2008 were
higher than the third quarter of 2009 due to higher market prices for diluent,
as well as increased volumes purchased since the Upgrader was not yet
processing bitumen.
Diluent and feedstock purchases were $78 million for the nine months
ended September 30, 2009 compared to $89 million the corresponding period of
2008. Diluent and feedstock purchases in 2009 include purchases for the entire
period, whereas diluent and feedstock purchases in 2008 only include purchases
from July 1, 2008, which is the date we determined the SAGD facility to be
ready for its intended use.
(x) Transportation
Transportation expenses were $3 million for the three month periods ended
September 30, 2009 and June 30, 2009, and $2 million for the three months
ended September 30, 2008. Transportation expenses were primarily related to
pipeline costs associated with PSC(TM) and PSH sales.
Transportation expenses were $9 million for the nine months ended
September 30, 2009 compared to $2 million in the corresponding period of 2008.
Transportation expenses in 2009 include expenses for the entire period,
whereas transportation expenses in 2008 are only included from July 1, 2008,
which is the date we determined the SAGD facility to be ready for its intended
use.
(x) Net interest expense
Net interest expense was $46 million for the three months ended September
30, 2009, compared to $42 million in the three months ended June 30, 2009, and
$18 million in the three months ended September 30, 2008. Interest expense
increased in the third quarter of 2009 primarily due to higher average amounts
owing on the revolving credit facility and higher borrowing rates on this
facility, offset by lower interest costs on our U.S.-dollar-denominated debt
due to the stronger Canadian dollar in the third quarter of 2009 compared to
the previous quarter. Interest expense in the third quarter of 2008 only
included borrowing costs attributable to the SAGD facilities, as the Upgrader
was not yet ready for its intended use and borrowing costs related to the
Upgrader were capitalized.
Net interest expense was $107 million for the nine months ended September
30, 2009 compared to $14 million for the corresponding period of 2008. Net
interest expense in 2009 includes interest costs related to the SAGD
facilities for the entire period as well as interest costs related to the
Upgrader from April 1, 2009, whereas interest expenses in 2008 only includes
interest related to the SAGD facilities from July 1, 2008, which is the date
we determined the SAGD facility to be ready for its intended use.
(x) General and Administrative (G&A)
G&A expense was $2 million for the three months ended September 30, 2009,
compared to $7 million in the three months ended June 30, 2009 and $4 million
in the three months ended September 30, 2008. Second quarter 2009 expenses
were higher due to one-time transition costs related to the re-organization of
OPTI after the asset sale to Nexen. G&A expenses were lower in the third
quarter of 2009 than prior periods because we have reduced our head office
costs since we are no longer the operator of the Upgrader.
G&A expense was $15 million for the nine months ended September 30, 2009
compared to $12 million the corresponding period of 2008. The increase in 2009
is primarily due to one-time transition costs related to the re-organization
of OPTI after the working interest asset sale to Nexen.
(x) Financing charges
Financing charges were $4 million for the three months ended September
30, 2009, compared to $1 million in the three months ended June 30, 2009 and
$nil million in the three months ended September 30, 2008. Financing charges
in third quarter of 2009 are due to the amendment to our revolving debt
facility covenants, while the financing charges in the second quarter of 2009
relate to the evaluation of financing alternatives.
Financing charges were $5 million for the nine months ended September 30,
2009 compared to $1 million the corresponding period of 2008. Financing
charges in 2009 relate to the amendment to our revolving debt facility
covenants and evaluation of financing alternatives, while financing charges in
2008 relate to new debt facilities.
(x) Loss on disposal of assets
Loss on disposal of assets was $nil million for the three months ended
September 30, 2009, compared to $1 million in the three months ended June 30,
2009 and $nil million in the three months ended September 30, 2008. The loss
in the second quarter of 2009 relates to information technology write offs.
For the nine months ended September 30, 2009, loss on disposal of assets
was $2 million, primarily for costs incurred during the first quarter related
to the asset sale to Nexen and information technology write offs in the second
quarter. There were no asset disposals in the corresponding period in 2008.
(x) Foreign exchange gain or loss
The gain or loss is comprised of the re-measurement of our U.S.
dollar-denominated long-term debt and cash. Foreign exchange translation was a
$162 million gain for the three months ended September 30, 2009, compared to a
$171 million gain in the three months ended June 30, 2009 and a $73 million
loss in the three months ended September 30, 2008. During the third quarter of
2009 the Canadian dollar strengthened from CDN$1.16:US$1.00 to
CDN$1.07:US$1.00, while in second quarter of 2009 the Canadian dollar
strengthened from CDN$1.26:US$1.00 to CDN$1.16:US$1.00, resulting in a foreign
exchange translation gain in each quarter. In the third quarter of 2008, the
Canadian dollar weakened from CDN$1.02:US$1.00 to CDN$1.06:US$1.00, resulting
in a foreign exchange loss.
For the nine months ended September 30, 2009, foreign exchange
translation gain was $258 million compared to a loss of $119 million in 2008.
The Canadian dollar strengthened from CDN$1.22:US$1.00 to CDN$1.07:US$1.00 in
the first nine months of 2009.
(x) Net realized gain or loss on hedging instruments
Net realized gain on hedging instruments was $5 million for the three
months ended September 30, 2009, compared to $11 million in the three months
ended June 30, 2009 and $4 million in the three months ended September 30,
2008. The gains in 2009 are related to our US$80/bbl crude oil puts and our
US$77/bbl crude oil swaps since we realize gains on these contracts to the
extent the contract price exceeds the West Texas Intermediate (WTI) price. WTI
averaged US$68.38 during the third quarter of 2009 and US$59.62 during the
second quarter of 2009. The gain in the third quarter of 2008 is related to
gains on a foreign exchange hedging program which settled quarterly.
For the nine months ended September 30, 2009 and 2008, net realized gain
on hedging instruments was $40 million and $8 million, respectively. The gain
in 2009 is related to our US$80/bbl crude oil puts and our US$77/bbl crude oil
swaps, while the gain in 2008 is related to gains on a foreign exchange
hedging program.
(x) Net unrealized gain or loss on hedging instruments
Net unrealized gain or loss on hedging instruments was an $82 million
loss for the three months ended September 30, 2009, compared to a $137 million
loss in the three months ended June 30, 2009 and a $64 million gain in the
three months ended September 30, 2008. The net unrealized loss in the third
quarter of 2009 is comprised of a $78 million unrealized loss on our foreign
exchange hedges due to the strengthening of the Canadian dollar and a $4
million unrealized loss on our commodity hedges as the future price of WTI
increased during the quarter. The net unrealized loss in the second quarter of
2009 is comprised of an $82 million unrealized loss on our foreign exchange
hedges due to the strengthening of the Canadian dollar and a $55 million
unrealized loss on our commodity hedges as the future price of WTI increased
during the quarter. The net unrealized gain in the third quarter of 2008 is
comprised of a $55 million unrealized gain on our foreign exchange hedges due
to the weakening of the Canadian dollar and a $9 million unrealized gain on
our commodity hedges as the future price of WTI decreased during the quarter.
For the nine months ended September 30, 2009, we had a net unrealized
loss of $198 million compared to a gain of $68 million in the corresponding
period in 2008. The unrealized loss in 2009 was due to a loss of $124 million
on our foreign exchange hedges as the Canadian dollar strengthened and a $74
million mark to market loss on our commodity hedges as the future price of WTI
increased over the first nine months of 2009. The unrealized gain in 2008 was
due to a gain of $65 million on our foreign exchange hedges as the Canadian
dollar weakened and a $3 million mark-to-market gain on our commodity hedges
as the future price of WTI decreased.
For the remainder of 2009, our commodity hedges are comprised of a 6,000
bbl/d put option at a net price of approximately US$76/bbl and a 500 bbl/d
swap at US$77/bbl. For 2010, our commodity hedges are comprised of WTI
commodity price swaps for 3,000 bbl/d at strike prices between US$64/bbl and
US$67/bbl.
(x) Depletion, depreciation and amortization
Depletion, depreciation and amortization (DD&A) was $5 million for the
three months ended September 30, 2009, compared to $7 million in the three
months ended June 30, 2009 and $6 million in the three months ended September
30, 2008. The decrease in the third quarter of 2009 against both comparative
periods is due to lower bitumen and PSC(TM) production, resulting in a lower
unit of production DD&A charge.
For the nine months ended September 30, 2009, DD&A was $16 million
compared to $7 million in 2008. DD&A in 2009 is based on nine months of use of
the SAGD facilities and six months of use of the Upgrader from April 1, 2009,
which is the date we determined the Upgrader to be ready for its intended use.
(x) Future tax (recovery)
Future tax recovery is primarily related to the future tax benefit
derived from losses before tax, net of a valuation allowance in respect of
non-capital losses which are expected to expire unutilized. Future tax
recovery was $22 million for the three months ended September 30, 2009,
compared to $32 million in the three months ended June 30, 2009 and $4 million
in the three months ended September 30, 2008. For the nine months ended
September 30, 2009, future tax recovery was $47 million compared to $13
million in 2008.
CAPITAL EXPENDITURES
The table below identifies expenditures incurred by us in relation to the
Project, other oil sands activities and other capital expenditures.
<<
-------------------------------------------------------------------------
Three months Nine months
ended ended
September 30, September 30, Year ended
$ millions 2009 2009 2008
-------------------------------------------------------------------------
Long Lake Project - Phase 1
Upgrader & SAGD $ 3 $ 22 $ 480
Sustaining capital 20 50 60
Capitalized operations - 18 32
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Total Long Lake Project 23 90 572
Expenditures on future phases
Engineering and equipment 6 16 64
Resource acquisition and
delineation 2 22 70
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Total oil sands expenditures 31 128 706
Capitalized interest - 29 139
Other capital expenditures - (19) 35
-------------------------------------------------------------------------
Total cash expenditures 31 138 880
Non-cash capital charges - - 4
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Total capital expenditures $ 31 $ 138 $ 884
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>>
For the three months ended September 30, 2009 we incurred capital
expenditures of $31 million. Our $3 million share of the Phase 1 expenditures
for Upgrader and SAGD were primarily related to the ongoing construction and
commissioning of the steam expansion project, which is scheduled for start-up
in the fourth quarter of 2009.
As with all SAGD projects, new well pads must be drilled and tied into
the SAGD central facility in order to maintain production at design rates over
the life of the Project. In the third quarter, we had sustaining capital
expenditures of $20 million related primarily to completion of an additional
SAGD well pad (first steam to the wells is expected during the fourth quarter
of 2009), resource delineation for future Phase 1 well pads, as well as
optimization of the SAGD and Upgrader plants.
For the three months ended September 30, 2009, we incurred expenditures
of $6 million for engineering and $2 million for resource delineation for
future phases.
<<
SUMMARY FINANCIAL INFORMATION
-------------------------------------------------------------------------
In millions
(except per 2009 2008 2007
share ---------------------------------------------------------------
amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Revenue $ 38 $ 34 $ 29 $ 69 $ 126 $ - $ - $ -
-------------------------------------------------------------------------
Net
earnings
(loss) 12 (9) (97) (410) (32) (29) (6) 32
-------------------------------------------------------------------------
Earnings
(loss)
per
share,
basic and
diluted $ 0.04 $(0.04) $(0.50) $(2.09) $(0.16) $(0.14) $(0.03) $ 0.16
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>>
The disclosure and analysis with respect to summary financial information
has been updated to reflect the retroactive adoption of CICA Handbook section
3064 "Goodwill and Intangible Assets" on January 1, 2009.
Prior to the third quarter of 2008, earnings have been influenced by
fluctuating foreign exchange translation gains and losses primarily related to
re-measurement of our U.S. dollar-denominated long-term debt, fluctuating
realized and unrealized gains and losses on hedging instruments, and
fluctuating future tax expense. During the fourth quarter of 2007, we had a
$20 million unrealized gain on hedging instruments, a $6 million foreign
exchange translation gain and a $9 million recovery of future taxes primarily
as a result of a reduction in the applicable federal tax rate that increased
our earnings. During the third quarter of 2008, we had a $34 million
unrealized loss on hedging instruments.
In the third and fourth quarters of 2008, we generated revenue and
incurred operating expenditures associated with early stages of SAGD
operation. During the fourth quarter of 2008, we had a pre-tax asset
impairment for accounting purposes related to our working interest sale of
$369 million and a future tax expense recovery, primarily related to this
impairment, of $116 million, as well as a $254 million foreign exchange
translation loss, a $105 million realized gain and a $28 million unrealized
gain on hedging instruments.
The first, second and third quarters of 2009 represent initial stages of
operation at relatively low operating volumes and therefore our operating
results associated with these activities are expected to improve as SAGD
production increases and the Upgrader produces higher volumes of PSC(TM).
Refer also to explanations in results of operations regarding realized and
unrealized gains and losses related to foreign exchange translation and
hedging instruments under the headings "Net realized gain or loss on hedging
instruments" and "Net unrealized gain or loss on hedging instruments", above.
Earnings of $12 million in the third quarter of 2009 are primarily due to
a $162 million foreign exchange translation gain, which was offset by
unrealized losses on hedging instruments related to our foreign exchange and
commodity hedges and our net field operating loss.
SHARE CAPITAL
At October 15, 2009, OPTI had 281,749,526 common shares and 5,378,716
common share options outstanding, of which 1,465,000 common share options have
an exercise price of less than $3.50 per share. The common share options have
a weighted average exercise price of $8.58 per share. At October 15, 2009,
OPTI's fully diluted shares outstanding were 287,128,242.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2009, we have approximately $422 million of financial
resources, consisting of $207 million of cash on hand and $215 million undrawn
under our $350 million revolving credit facility. Our cash and cash
equivalents are invested exclusively in money market instruments issued by
major Canadian banks. Our long-term debt currently consists of US$1,750
million of Senior secured notes (Notes) and a $350 million revolving credit
facility.
For the three months ended September 30, 2009, cash used by operating
activities was $3 million, cash used by financing activities was $46 million
and cash used by investing activities was $56 million. These changes, combined
with a loss on our U.S. dollar-denominated cash of $1 million, resulted in a
decrease in cash and cash equivalents during the period of $106 million.
During the third quarter of 2009, we used existing cash and net proceeds
from our equity issuance to reduce the balance of our revolving credit
facility. For the remainder of 2009, cash and availability under our revolving
credit facilities are expected to fund our expenditures.
Our rate of production increase after the recently completed turnaround
will have a significant impact on our financial position through 2010 and
beyond. Primarily due to the plant turnaround completed in the third quarter,
our net field operating margin in the most recent quarter is a loss. It is
important for our business to increase production to a point where we generate
positive net field operating margin. Failure to significantly increase bitumen
production from current rates, and ultimately PSC(TM) sales, will result in
continued net field operating losses, difficulty in obtaining new credit and
capital, and will limit the amount of new borrowings and may accelerate timing
of repayments on our revolving credit facility. We will monitor the initial
production levels as these will impact the rate and timing of production
increases in 2010. Based on these initial production levels and rates of
increase, we may determine that we require additional capital to maintain
adequate liquidity through the ramp-up of the Project.
Our debt facilities contain a number of provisions that serve to limit
the amount of debt we may incur. With respect to our revolving credit
facility, the key maintenance covenants are with respect to the ratio of debt
outstanding under the revolving credit facility to earnings before interest,
taxes and depreciation (EBITDA), and total debt to capitalization. Maintenance
covenants are important as they are ongoing conditions that must be satisfied
to comply with the terms of the revolving credit facility.
The revolving credit facility debt to EBITDA covenant, which is measured
quarterly, was amended in the third quarter of 2009 and now commences in the
first quarter of 2010. Under this covenant, this ratio must be lower than
3.5:1 commencing for the quarter ended March 31, 2010. The first three
measurements of EBITDA for this covenant will annualize EBITDA as measured
from January 1, 2010, to the end of the applicable covenant period.
Thereafter, EBITDA will be based on a trailing four quarters. Realized cash
gains on commodity contracts, such as our existing puts and forwards, are
included in EBITDA for the purposes of the covenant.
In the first quarter of 2010 and subsequent quarters, our compliance with
the covenant as currently structured will depend on our operating performance.
Although commodity pricing has an impact, the most important factor in
determining whether or not we will generate sufficient EBITDA to meet this
covenant will be the amount of PSC(TM) revenue we generate. We will need to
achieve a significant increase in bitumen production from current levels,
which at this point is not assured, to generate sufficient PSC(TM) revenue and
therefore EBITDA to meet the covenant. Other risks related to compliance with
the EBITDA covenant include commodity pricing, operating costs and capital
expenditures. Commodity pricing is a less significant risk in 2010, as we have
hedged 3,000 bbl/d with swaps at strike prices between US$64 and US$67 per
barrel (risks associated with our hedging instruments are discussed in more
detail under "Financial Instruments"). Should operating or capital costs be
greater than anticipated, we would require additional SAGD and PSC(TM) volumes
in order to meet this covenant. The majority of our operating and interest
costs are fixed. Aside from changes in the price of natural gas, our costs
will neither decrease nor increase significantly as a result of fluctuations
in WTI prices other than with respect to royalties to the Provincial
Government of Alberta, which increase on a sliding scale at WTI prices higher
than CDN$55/bbl.
The total debt to capitalization covenant requires that we do not exceed
a ratio of 70 percent as calculated on a quarterly basis. The covenant is
calculated based on the book value of debt and equity. The book value of debt
is adjusted for the effect of any foreign exchange derivatives issued in
connection with the debt that may be outstanding. Our capitalization is
adjusted to exclude the $369 million increase to deficit as a result of the
asset impairment associated with the working interest sale to Nexen and the
$85 million increase to the January 1, 2009 opening deficit as a result of new
accounting pronouncements effective on that date. At September 30, 2009, this
means for the purposes of this covenant calculation that our debt would be
increased by the value of our foreign exchange forward liability in the amount
of $92 million and our deficit would be reduced by $454 million. With respect
to U.S.-dollar-denominated debt, for purposes of the total debt to
capitalization ratio, the debt is translated to Canadian dollars based on the
average exchange rate for the quarter. The total debt to capitalization is
therefore influenced by the variability in the measurement of the foreign
exchange forward, which is subject to mark to market variability and average
foreign exchange rate changes during the quarter.
In respect of each new borrowing under the $350 million revolving credit
facility, we must satisfy certain conditions precedent prior to making a new
borrowing. We must confirm that the representations and warranties in our loan
documents are correct on the date of the new borrowing, that no event of
default has occurred and that there has not been a change or development that
would constitute a material adverse effect.
With respect to our Notes, the covenants are in place primarily to limit
the total amount of debt that OPTI may incur at any time. This limit is most
affected by the present value of our total proven reserves using forecast
prices discounted at 10 percent. Based on our 2008 reserve report, as adjusted
for our new working interest in the joint venture, we have sufficient capacity
under this test to incur significant additional debt beyond our existing $350
million revolving credit facility and existing Notes. Other leverage
considerations, such as total debt to capitalization and total debt to EBITDA,
are expected to be more constraining than this limitation.
We have semi-annual interest payments of US$71 million in June and
December of each year until maturity of the Notes in 2014. On a long term
basis, we estimate our share of capital expenditures required to sustain
production of Phase 1 at or near planned capacity for the Project will be
approximately $60 million per year prior to the effects of inflation. We
expect to fund these payments from future operating cash flow and from
existing financial resources that includes the available portion of the
revolving credit facility.
Access to capital markets for new equity and debt have improved
considerably during 2009. However, there can be no assurance that these
positive market conditions will continue nor that they will provide a
constructive market for OPTI to access additional capital if we are required
to do so. Delays in ramp-up of SAGD production, operating issues with the SAGD
or Upgrader operations or deterioration of commodity prices could result in
additional funding requirements earlier than we have estimated. Should the
Company require such funding, it may be difficult to obtain such financing.
CREDIT RATINGS
OPTI maintains a company rating and a rating for its revolving credit
facility and Senior Notes with Moody's Investor Service (Moody's) and Standard
and Poor's (S&P). Please refer to the table below for the respective ratings.
<<
Moody's S&P
------- ---
OPTI Corporate Rating Caa1 B-
Revolving Credit Facility B1 B+
8.25% Notes Caa1 B
7.875% Notes Caa1 B
>>
The Moody's ratings were confirmed in September 2009, with the outlook
changed to negative from under review. The S&P rating was put on credit watch
with negative implications in June 2009.
A security rating is not a recommendation to buy, sell or hold securities
and may be subject to revision or withdrawal at any time by the rating
organization.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
During the three months ended September 30, 2009, our long term debt
decreased by $349 million due to payments on our long term revolving credit
facility, as well as due to a lower Canadian dollar equivalent amount for our
Notes (principal and interest) due exclusively to a stronger Canadian dollar.
The following table shows our contractual obligations and commitments
related to financial liabilities at September 30, 2009.
<<
-------------------------------------------------------------------------
Remaining 2010 - 2012 -
In $ millions Total 2009 2011 2013 Thereafter
-------------------------------------------------------------------------
Accounts payable
and accrued
liabilities(1) $ 80 $ 80 $ - $ - $ -
Long-term debt (Notes
- principal)(2) 1,874 - - - 1,874
Long-term debt
(Notes - interest)(3) 836 76 304 304 152
Long-term debt
(Revolving)(4) 135 - 135 - -
Capital leases(5) 69 1 6 6 56
Operating leases and
other commitments(6) 74 3 20 20 31
Contracts and purchase
orders(7) 9 9 - - -
-------------------------------------------------------------------------
Total commitments $ 3,077 $ 169 $ 465 $ 330 $ 2,113
-------------------------------------------------------------------------
Notes:
(1) Excludes accrued interest expense related to the Notes.
(2) Consists of principal repayments on the Notes, translated into
Canadian dollars using an exchange rate of CDN$1.07 to US$1.00 at
September 30, 2009.
(3) Consists of scheduled interest payments on the Notes, translated into
Canadian dollars using an exchange rate of CDN$1.07 to US$1.00 at
September 30, 2009.
(4) Consists of $135 million drawn on the revolving credit facility. The
repayment represents only the final repayment of the facility at its
scheduled maturity in 2011. In addition, we are contractually
obligated for interest payments on borrowings and standby charges in
respect to undrawn amounts under the revolving credit facility, which
are not reflected in the above table as amounts cannot reasonably be
estimated due to the revolving nature of the facility and variable
interest rates. In addition, such interest amounts are not material
relative to our other commitments.
(5) Consists of our share of future payments under our product
transportation agreements with respect to future tolls during the
initial contract term.
(6) Consists of our share of payments under our product transportation
agreements with respect to future tolls during the initial contract
term.
(7) Consists of our share of commitments associated with contracts and
purchase orders in connection with the Long Lake Project and our
other oil sands activities associated with future phases.
>>
NETBACKS
We have provided below an update to our estimated netback for Phase 1 of
the Project that was last updated in our MD&A filed on SEDAR on July 28, 2009.
The netback calculation at each WTI price has been updated for operating cost
expectations and is now presented on a pre-payout basis with respect to crown
royalties Management approved this netback calculation on October 14, 2009.
This financial outlook is intended to provide investors with a measure of
the ability of our Project to generate netbacks assuming full production
capacity. We believe that the ability of the Project to generate cash to fund
interest payments and invest in capital expenditures is a key advantage of our
Project and important to our investors. We believe the netback measure is the
most appropriate financial gauge to demonstrate this ability as corporate
costs (other than corporate G&A expenses), interest, and other non-cash items
are excluded from the calculation. The financial outlook may not be suitable
for other purposes. We expect netbacks generated by our Project to be lower
than shown in this outlook in the initial years following start-up due to the
lower production volumes during ramp-up and an initially higher SOR. The
netback calculation as presented is a non-GAAP financial measure. The closest
GAAP financial measure to the netback calculation is cash flow from
operations. However, cash flow from operations includes many other corporate
items that affect cash and are independent of the operations of the Project.
The actual netbacks achieved by the Project could differ materially from
these estimates. The material risk factors that we have identified toward
achieving these netbacks are outlined under "Forward Looking Information" in
our AIF. In particular, the SAGD and Long Lake Upgrader facilities may not
operate as planned; the operating costs of the Project may vary considerably
during the operating period; our results of operations will depend upon the
prevailing prices of oil and natural gas which can fluctuate substantially; we
will be subject to foreign currency exchange fluctuation exposure; and our
netback will be directly affected by the applicable royalty regime relating to
our business. The key assumptions relating to the netback estimate are set out
in the notes beneath the table.
<<
Estimated Future Project Post-Payout Netbacks(1)
WTI - WTI - WTI -
US$60(2) US$75(3) US$90(4)
----------- ----------- -----------
$/bbl $/bbl $/bbl
----------- ----------- -----------
Revenue(1) $ 76.44 $ 87.34 $ 96.48
Royalties and Corporate G&A (3.28) (4.36) (5.55)
Operating costs(5)
Natural gas(6) (3.51) (4.00) (4.41)
Other variable(7) (2.00) (2.00) (2.00)
Fixed (15.46) (15.46) (15.46)
Property taxes and insurance(8) (2.81) (2.81) (2.81)
----------- ----------- -----------
Total operating costs (23.78) (24.27) (24.68)
Netback $ 49.38 $ 58.71 $ 66.25
Notes:
(1) The per barrel amounts are based on the expected yield for the
Project of 57,700 bbl/d of PSC(TM) and 800 bbl/d of butane, and
assume that the Upgrader will have an on-stream factor of 96 percent.
These numbers are cash costs only and do not reflect non-cash
charges. See "Note Regarding Forward-Looking Statements".
(2) For purposes of this calculation, with regard to the WTI price
scenario of US$60, we have assumed natural gas costs of US$6.00/mcf,
foreign exchange rates of $1.00 (equal sign) US$0.775, heavy/light
crude oil price differentials of 32 percent of WTI and electricity
sales prices of $92.66 per MWh. Revenue includes sale of PSC(TM),
bitumen, butane and electricity.
(3) For purposes of this calculation, with regard to the WTI price
scenario of US$75, we have assumed natural gas costs of US$7.50/mcf,
foreign exchange rates of $1.00 (equal sign) US$0.850, heavy/light
crude oil price differentials of 30 percent of WTI and electricity
sales prices of $105.61 per MWh. Revenue includes sale of PSC(TM),
bitumen, butane and electricity.
(4) For purposes of this calculation, with regard to the WTI price
scenario of US$90, we have assumed natural gas costs of US$9.00/mcf,
foreign exchange rates of $1.00 (equal sign) US$0.925, heavy/light
crude oil price differentials of 28 percent of WTI and electricity
sales prices of $116.45 per MWh. Revenue includes sale of PSC(TM),
bitumen, butane and electricity.
(5) Costs are in 2009 dollars.
(6) Natural gas costs are based on our long-term estimate for a SOR of
3.0.
(7) Includes approximately $1.00/bbl for greenhouse gas mitigation costs
based on an approximate average 20 percent reduction of CO2 emissions
at a cost of $20 per tonne of CO2.
(8) Property taxes are based on expected mill rates for 2009.
>>
We estimate sustaining capital costs required to maintain production at
design rates of capacity to be approximately $8.00 to $9.00 per barrel of
PSC(TM), assuming full design rate production adjusted for long-term on-stream
expectations. The netbacks as shown are prior to abandonment and reclamation
costs. We do not include any of the foregoing costs in our netback estimates
due to the long-term nature of our assets.
Based on US$60WTI and the other assumptions set out in the notes above,
we expect our operating costs plus royalties and corporate G&A expenses to be
$27.06 per barrel of products sold. Using a foreign exchange rate of CDN$1.00
(equal sign) US$0.775, the annual interest on our senior secured notes is approximately
$25.00 per barrel of products sold. Based on this, at full production volumes,
our revenue will exceed our estimated operating costs, royalties prior to
payout, corporate G&A expenses and interest on our senior secured notes at
approximately $52.00 per barrel (US$40.00 per barrel (WTI)) of products sold.
CONFERENCE CALL
OPTI Canada Inc. will conduct a conference call at 6:30 a.m. Mountain
Time (8:30 a.m. Eastern Time) on Wednesday, October 28, 2009 to review the
Company's third quarter 2009 financial and operating results. Chris Slubicki,
President and Chief Executive Officer, and Travis Beatty, Vice President,
Finance and Chief Financial Officer, will host the call. To participate in the
conference call, dial:
<<
(800) 814-4860 (North American Toll-Free)
(416) 644-3419 (Alternate)
>>
Please reference the OPTI Canada conference call with Chris Slubicki when
speaking with the Operator.
A replay of the call will be available until November 11, 2009,
inclusive. To access the replay, call (416) 640-1917 or (877) 289-8525 and
enter passcode 4176079, followed by the pound sign.
This call will also be webcast, and can be accessed on OPTI Canada's
website under "Presentations and Webcasts" in the "For Investors" section. The
webcast will be available for replay for a period of 30 days. The webcast may
alternatively be accessed at:
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)2852960.
ABOUT OPTI
OPTI Canada Inc. is a Calgary, Alberta-based company focused on
developing major oil sands projects in Canada using our proprietary
OrCrude(TM) process. Our first project, Phase 1 of Long Lake, consists of
72,000 barrels per day of SAGD oil production integrated with an upgrading
facility. The upgrader uses the OrCrude(TM) process combined with commercially
available hydrocracking and gasification. Through gasification, this
configuration substantially reduces the exposure to and the need to purchase
natural gas. On a 100 percent basis, the Project is expected to produce 58,500
bbl/d of products, primarily 39 degree API Premium Sweet Crude with low
sulphur content, making it a highly desirable refinery feedstock. Due to its
premium characteristics, we expect PSC(TM) to sell at a price similar to West
Texas Intermediate (WTI) crude oil. The Long Lake Project is being operated in
a joint venture with Nexen Inc. OPTI holds a 35 percent working interest in
the joint venture. OPTI's common shares trade on the Toronto Stock Exchange
under the symbol OPC.
FORWARD-LOOKING INFORMATION
Certain statements contained herein are forward-looking statements,
including, but not limited to, statements relating to: the expected production
performance of the Long Lake Project (the Project); the rate of increase of
bitumen production, which may not be consistent with other SAGD projects or
SAGD industry experience; OPTI Canada Inc.'s (OPTI) other business prospects,
expansion plans and strategies; the cost, development and operation of the
Long Lake Project and OPTI's relationship with Nexen Inc.; OPTI's financial
outlook respecting the estimate of the netback for Phase 1 of the Project;
OPTI's anticipated financial condition and liquidity over the next 12 to 24
months; and our estimated future tax asset. Forward-looking information
typically contains statements with words such as "intends," "anticipate,"
"estimate," "expect," "potential," "could," "plan" or similar words suggesting
future outcomes. Readers are cautioned not to place undue reliance on
forward-looking information because it is possible that expectations,
predictions, forecasts, projections and other forms of forward-looking
information will not be achieved by OPTI. By its nature, forward-looking
information involves numerous assumptions, inherent risks and uncertainties. A
change in any one of these factors could cause actual events or results to
differ materially from those projected in the forward-looking information.
Although OPTI believes that the expectations reflected in such forward-looking
statements are reasonable, OPTI can give no assurance that such expectations
will prove to be correct. Forward-looking statements are based on current
expectations, estimates and projections that involve a number of risks and
uncertainties which could cause actual results to differ materially from those
anticipated by OPTI and described in the forward-looking statements or
information. The forward-looking statements are based on a number of
assumptions that may prove to be incorrect. In addition to other assumptions
identified herein, OPTI has made assumptions regarding, among other things:
market costs and other variables affecting operating costs of the Project; the
ability of the Long Lake Project joint venture partners to obtain equipment,
services and supplies, including labour, in a timely and cost-effective
manner; the availability and costs of financing; oil prices and market price
for PSC(TM) output of the OrCrude(TM) Upgrader; foreign currency exchange
rates and hedging risks. Other specific assumptions and key risks and
uncertainties are described elsewhere in this document and in OPTI's other
filings with Canadian securities authorities.
Readers should be aware that the list of assumptions, risks and
uncertainties set forth herein are not exhaustive. Readers should refer to
OPTI's current Annual Information Form (AIF), which is available at
www.sedar.com, for a detailed discussion of these assumptions, risks and
uncertainties. The forward-looking statements or information contained in this
document are made as of the date hereof and OPTI undertakes no obligation to
update publicly or revise any forward-looking statements or information,
whether as a result of new information, future events or otherwise, unless so
required by applicable laws or regulatory policies.
Additional information relating to our Company, including our AIF, can be
found at www.sedar.com.
%CIK: 0001177446
/For further information: OPTI Canada Inc., (403) 249-9425/
(OPC.)
CO: OPTI Canada Inc.
CNW 05:00e 28-OCT-09
