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
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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)
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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)
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Net earnings (loss) $ 12 $ (9) $ (32) $ (95) $ (67)
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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
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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
--------------------------
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
(*) 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.
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Three months Nine months
ended ended
September 30, September 30, Year ended
$ millions 2009 2009 2008
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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
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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
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In millions
(except per 2009 2008 2007
share ---------------------------------------------------------------
amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
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Revenue $ 38 $ 34 $ 29 $ 69 $ 126 $ - $ - $ -
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Net
earnings
(loss) 12 (9) (97) (410) (32) (29) (6) 32
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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
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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.
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Remaining 2010 - 2012 -
In $ millions Total 2009 2011 2013 Thereafter
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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 - - -
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Total commitments $ 3,077 $ 169 $ 465 $ 330 $ 2,113
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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 = 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 = 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 = 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 = 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=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
.