Exhibit 99.1
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the period ended
June 30, 2009
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis (MD&A) dated July 28, 2009, should be read in conjunction with the revised audited financial statements filed on SEDAR on June 3, 2009 and accompanying MD&A for the year ended December 31, 2008, and the unaudited financial statements for the three and six month periods ended June 30, 2009.
FORWARD-LOOKING INFORMATION
The MD&A is a review of our financial condition and results of operations. Our financial statements are prepared based upon Canadian Generally Accepted Accounting Principles (GAAP) and all amounts are in Canadian dollars unless specified otherwise. 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); 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. (Nexen); 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 the Premium Sweet Crude (PSC™) output of the OrCrude™ Upgrader (the 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.
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FINANCIAL SUMMARY
In millions | Three months ended June 30, 2009 | Six months ended June 30, 2009 | Year ended December 31, 2008 | |||||||||
| Net loss | $ | (9 | ) | $ | (106 | ) | $ | (477 | ) (1) | |||
Total oil sands expenditures (2) | 22 | 97 | 706 | |||||||||
| Working capital (deficiency) | 255 | 255 | (25 | ) | ||||||||
| Shareholders’ equity | $ | 1,366 | $ | 1,366 | $ | 1,471 | ||||||
Common shares outstanding (basic) (3) | 196 | 196 | 196 | |||||||||
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) | On July 14, 2009, OPTI issued an additional 85,720,000 common shares, which increased the common shares outstanding to 281,749,526. See “Share Capital”. |
PROJECT STATUS
The ramp-up of the Project is progressing and the reservoir continues to perform as OPTI expected, given the amount of steam that has been injected. Steam volumes have been limited by the ability to treat water.
In May, a project to add supplementary heat to the hot lime softeners (HLS) in the water treatment plant was successfully completed. Routine maintenance work to remove deposits which typically build up in water treatment plants was also completed. Steam production increased and in June we have achieved injection rates of approximately 95,000 bbl/d. Gross bitumen production rates reached a peak of approximately 18,000 bbl/d in June. At June 30, 2009, there were 41 of 81 well pairs on production operating with a steam to oil ratio (SOR) that ranges between 4.0 and 5.0. We continue to anticipate a long-term SOR of 3.0.
Bitumen production volumes for the second quarter averaged approximately 14,300 bbl/d (gross). Production volumes in the second quarter were impacted by downtime associated with improvements made to the HLS units.
In mid-July, steam injection rates were intentionally reduced in order to address water chemistry issues in advance of planned maintenance in the third quarter. As a result, average bitumen production volumes for the period July 1 to July 26 averaged approximately 13,000 bbl/d. As these issues are resolved, steam and bitumen volumes have begun to ramp-up again to approximately 69,000 bbl/d and 14,500 bbl/d, respectively.
As previously announced, a project to replace valves and conduct maintenance on the water treatment plant during the third quarter of 2009 is planned to further optimize steam production. We expect the cost of these activities will not be significant but will result in scheduled downtime in the third quarter, impacting bitumen and Premium Sweet Crude (PSC™) production.
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As steam generation increases, we expect that all remaining wells will be converted to production mode. We expect steam assisted gravity drainage (SAGD) volumes to increase from current production levels, other than the short-term reduction in the third quarter of 2009 noted above, to full capacity of 72,000 bbl/d of bitumen in late 2010. During the SAGD ramp-up period in 2009 and 2010, we also expect to process third party bitumen.
With respect to the Upgrader, all major units are operational and synthesis gas has been used in SAGD operations, decreasing operating costs by reducing the requirement for purchased natural gas. Upgrader reliability is improving with an on-stream factor of 46% during the second quarter of 2009 compared to 33% in the first quarter of 2009. The PSC™ that has been marketed has, on average, been sold at pricing equal to or above pricing for other synthetic crude oils.
Having successfully operated the Upgrader for several months, the Operator intentionally shut down the Upgrader last week to assist in dealing with water chemistry issues impacting steam generation for SAGD operations. When the Upgrader is restarted, we expect to be in a position to start-up the solvent de-asphalter and thermal cracker units. This is expected to take place shortly before or after the planned maintenance in the third quarter. These units will allow the Operator to transition from gasifying vacuum residue, which contains some lighter parts of the barrel, to gasifying asphaltenes, the heaviest part of the barrel. Once this transition is complete we expect the PSC™ yields to increase to approximately 80%. In periods when the Upgrader is shut down, we will continue to produce bitumen and blend it with diluent for sale.
While we expect periods of downtime in the ramp-up phase we anticipate that the reliability of operations will continue to improve. We anticipate Upgrader capacity during ramp-up will be capable of processing all of the forecasted SAGD volumes and we expect the Project to reach full capacity of approximately 58,500 bbl/d of PSC™ and other products in late 2010.
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CAPITAL EXPENDITURES
As Phase 1 of the Long Lake Project is essentially complete the remaining capital costs relate to the completion of the steam expansion project, expected later this year, and the ash processing unit in 2010. The remaining cost to complete these two projects is approximately $34 million net to OPTI, most of which will be incurred in 2010.
The table below identifies historical expenditures incurred by us in relation to the Project, other oil sands activities and other capital expenditures.
| $ millions | Three months ended June 30, 2009 | Six months ended June 30, 2009 | Year ended 2008 | |||||||||
| Long Lake Project - Phase 1 | ||||||||||||
Upgrader & SAGD | $ | 6 | $ | 19 | $ | 480 | ||||||
Sustaining capital | 9 | 30 | 60 | |||||||||
Capitalized operations | - | 18 | 32 | |||||||||
| Total Long Lake Project | 15 | 67 | 572 | |||||||||
| Expenditures on future phases | ||||||||||||
Engineering and equipment | 5 | 10 | 64 | |||||||||
Resource acquisition and delineation | 2 | 20 | 70 | |||||||||
| Total oil sands expenditures | 22 | 97 | 706 | |||||||||
| Capitalized interest | - | 29 | 139 | |||||||||
| Other capital expenditures | - | (19 | ) | 35 | ||||||||
| Total cash expenditures | 22 | 107 | 880 | |||||||||
| Non-cash capital charges | - | - | 4 | |||||||||
| Total capital expenditures | $ | 22 | $ | 107 | $ | 884 | ||||||
For the three months ended June 30, 2009 we incurred capital expenditures of $22 million. Our $6 million share of the Phase 1 expenditures for Upgrader and SAGD were primarily related to the ongoing construction of the steam expansion project. Sustaining capital expenditures of $9 million related primarily to engineering and resource delineation for future Phase 1 well pads and SAGD optimization. We discontinued capitalizing our share of the net Upgrader operations on April 1, 2009.
For the three months ended June 30, 2009, we incurred expenditures of $5 million for engineering and $2 million for resource acquisition and delineation for future phases.
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RESULTS OF OPERATIONS
Three months and six months ended June 30, 2009
$ millions | Three months ended June 30, 2009 | Three months ended June 30, 2008 (as revised) | Six months ended June 30, 2009 | Six months ended June 30, 2008 (as revised) | ||||||||||||
| Revenue | $ | 34 | $ | - | $ | 63 | $ | - | ||||||||
| Expenses | ||||||||||||||||
Operating expenses | 39 | - | 67 | - | ||||||||||||
Diluent and feedstock purchases | 20 | - | 49 | - | ||||||||||||
Transportation | 3 | - | 6 | - | ||||||||||||
| Net field operating margin (loss) | (28 | ) | - | (59 | ) | - | ||||||||||
Interest, net | 42 | (1 | ) | 61 | (3 | ) | ||||||||||
General and administrative | 7 | 4 | 13 | 8 | ||||||||||||
Financing charges | 1 | 1 | 1 | 1 | ||||||||||||
Loss on disposal of assets | 1 | - | 2 | - | ||||||||||||
Foreign exchange translation loss (gain) | (171 | ) | (11 | ) | (96 | ) | 45 | |||||||||
Realized loss (gain) on hedging instruments | (11 | ) | 3 | (35 | ) | (4 | ) | |||||||||
| Income (loss) before non-cash items | 103 | 4 | (5 | ) | (47 | ) | ||||||||||
Net unrealized loss (gain) on hedging instruments | 137 | 40 | 115 | (4 | ) | |||||||||||
Depletion, depreciation and accretion | 7 | 1 | 11 | 2 | ||||||||||||
Future tax (recovery) | (32 | ) | (8 | ) | (25 | ) | (10 | ) | ||||||||
| Net income (loss) | $ | (9 | ) | $ | (29 | ) | $ | (106 | ) | $ | (35 | ) | ||||
Comparative amounts for the three and six months ended June 30, 2008 have been revised to reflect the retroactive adoption of CICA Handbook section 3064 “Goodwill and Intangible Assets”, effective January 1, 2009.
Operational Overview
Our overall operating results in the second quarter of 2009 and the six months ended June 30, 2009 reflected the inconsistent performance of SAGD and Upgrader operations and relatively low SAGD volumes. During the second quarter, we resolved some of the previously identified water treating issues, which is expected to lead to higher steam volumes and corresponding bitumen volumes. Both HLS units are operating with additional supplementary heat. The operating performance of the Upgrader improved considerably during the second quarter as the Upgrader had an on-stream factor of 46% during the quarter compared to 33% in the first quarter. On-stream factor is a measure of the period of time that the Upgrader is producing PSCTM and it is calculated as the percentage of hours the Hydrocracker Unit in the Upgrader is in operation. As previously announced, a project to replace valves and conduct maintenance on the water treatment plant during the third quarter of 2009 is planned, which is expected to increase steam production. We expect that the cost of these activities will not be significant but will result in scheduled downtime in the third quarter, reducing bitumen and PSC™ production. As steam generation increases, we expect that all wells will be converted to production mode.
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We define our net field operating margin as revenue related to petroleum products and power sales minus operating expenses, diluent and feedstock purchases and transportation costs. See “Non-GAAP Financial Measures”. This margin was a loss of $28 million during the three months ended June 30, 2009 as compared with a loss of $31 million in the preceding quarter. Our net field operating margin improved during the second quarter as a result of higher sales volumes and prices for PSC™, lower diluent costs as a result of more on-stream time and lower SAGD operating costs. These improvements were offset by the inclusion in our net field operating margin of $16 million for Upgrader operating costs (these costs were capitalized in the first quarter). As most of our SAGD and Upgrader operating costs are fixed, 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 in higher PSC™ sales and lower diluent costs.
The results of operations for the six month period ended June 30, 2009 include SAGD results for the entire period, as well as Upgrader results from April 1, 2009, which is the date we determined the Upgrader to be ready for its intended use.
Revenue
For the three months ended June 30, 2009, we earned revenue of $34 million. Our share of PSC™ sales averaged 1,700 bbl/day (Q1 2009: 700 bbl/day was included in capitalized operations) at an average price of approximately $65.50/bbl, while our share of Premium Synthetic Heavy (PSH) averaged 4,400 bbl/day (Q1 2009: 7,700 bbl/day) at an average price of approximately $58.50/bbl. During the second quarter we received pricing in-line with or better than other synthetic crude oils. Due to the premium characteristics of our PSCTM, we expect to increase the premium we receive relative to other synthetic crude oils as production, and therefore the availability of marketed PSCTM, increases. In the same period, we had power sales of $1 million representing 17,167 megawatt hours (MWh) of electricity sold at an average price of approximately $33/MWh.
For the six months ended June 30, 2009, we earned revenue of $63 million, which was comprised of $51 million PSH sales, $10 million of PSCTM sales and $2 million of power sales. There was no revenue recorded in the three and six month periods ending June 30, 2008 as the facilities were not considered to be ready for their intended use.
Expenses, gains and losses
* Operating expenses
Operating expenses were $39 million for the three months ended June 30, 2009 and $67 million for the six months ended June 30, 2009. For both periods, operating expenses were primarily comprised of natural gas, maintenance, labour and operating materials and services. Operating expenses increased from $28 million in the first quarter to $39 million because we ceased capitalization of Upgrader operations effective April 1, 2009. In the second quarter, operating expenses improved compared to the first quarter as we benefited from lower natural gas costs due to lower prices, as well as reduced maintenance costs related to start-up activities. There were no operating expenses recorded in the corresponding periods in 2008. These costs were capitalized as the facilities were not considered to be ready for their intended use.
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* Diluent and feedstock purchases
Diluent and feedstock purchases were $20 million for the three months ended June 30, 2009 and $49 million for the six months ended June 30, 2009. Diluent costs in the three months ended June 30, 2009 are lower than the three months ended March 31, 2009 as a result of a higher on-stream factor for the Upgrader and a portion of our PSCTM production was used as diluent for our bitumen production. Diluent purchases averaged approximately $69/bbl in the second quarter, while the year-to-date average was approximately $66/bbl. There were no diluent or feedstock purchases included in operations in the corresponding periods in 2008 since these costs were capitalized as the facilities were not considered to be ready for their intended use.
* Transportation
Transportation expenses were $3 million for the three months ended June 30, 2009 and $6 million for the six months ended June 30, 2009, primarily related to pipeline costs associated with PSCTM and PSH sales. There were no transportation expenses included in operations in the corresponding periods in 2008 since these costs were capitalized as the facilities were not considered to be ready for their intended use.
* Net interest expense
Net interest expense was $42 million for the three months ended June 30, 2009 and $61 million for the six months ended June 30, 2009. Interest expense increased in the second quarter as we no longer capitalize interest attributable to the Upgrader. In 2008, $1 million of interest income was earned in the three months ended June 30, 2008, while $3 million of interest income was earned in the six months ended June 30, 2008. There was no interest costs included in expenses in the corresponding periods in 2008, as this cost was capitalized since the facilities were not considered to be ready for their intended use.
* General and Administrative (G&A)
For the three months ended June 30, 2009 G&A expenses increased to $7 million from $4 million in the corresponding period in 2008. For the six months ended June 30, 2009, G&A expenses increased to $13 million from $8 million in the corresponding period in 2008. The increase for the three and six month period is due to one-time transition costs related to the re-organization of OPTI after the asset sale to Nexen.
* Financing charges
For the three and six months ended June 30, 2009, financing charges were $1 million, which is consistent with the corresponding periods in 2008. Financing charges in 2009 relate to the evaluation of financing alternatives, while financing charges in 2008 relate to issuance of new debt facilities.
* Loss on disposal of assets
Loss on disposal of assets was $1 million for the three months ended June 30, 2009 and $2 million for the six months ended June 30, 2009. The loss relates to information technology write offs in the second quarter and costs incurred during the first quarter related to the asset sale to Nexen. There were no asset disposals in the corresponding periods in 2008.
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* 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. For the three months ended June 30, 2009, foreign exchange translation gain increased to $171 million from $11 million in 2008. The Canadian dollar strengthened from CDN$1.26 to US$1.00 to CDN$1.16 to US$1.00 in the three months ended June 30, 2009. For the six months ended June 30, 2009, foreign exchange translation gain was $96 million compared to a loss of $45 million in 2008. The Canadian dollar strengthened from CDN$1.22 to US$1.00 to CDN$1.16 to US$1.00 in the first six months of 2009.
* Net realized gain or loss on hedging instruments
Net realized gain on hedging instruments was $11 million for the three months ended June 30, 2009 and $35 million for the six months ended June 30, 2009. The gains in both periods 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$59.62 during the three months ended June 30, 2009 and averaged US$51.35 during the six months ended June 30, 2009.
* Net unrealized gain or loss on hedging instruments
For the three months ended June 30, 2009, we had a net unrealized loss of $137 million compared to a loss of $40 million in the corresponding period in 2008. The net unrealized loss is comprised of an $82 million unrealized loss on our foreign exchange hedges due to the strengthening of the Canadian dollar from CDN$1.26 to US$1.00 to CDN$1.16 to US$1.00 and a $55 million unrealized loss on our commodity hedges as the future price of WTI increased during the quarter.
For the six months ended June 30, 2009, we had a net unrealized loss of $115 million compared to a loss of $4 million in the corresponding period in 2008. The unrealized loss in 2009 was due to a loss of $45 million on our foreign exchange hedges as the Canadian dollar strengthened from $1.22 to US$1.00 to CDN$1.16 to US$1.00 and a $70 million mark to market loss on our commodity hedges as the future price of WTI increased over the first six months of 2009.
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 West Texas Intermediate (WTI) swap options that provide for 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl.
* Depletion, depreciation and amortization
For the three months ended June 30, 2009, depletion, depreciation and amortization was $6 million compared to $1 million in 2008. For the six months ended June 30, 2009, depletion, depreciation and amortization was $11 million compared to $2 million in 2008. The increase for the three and six month periods compared to the corresponding periods in 2008 is due to the Upgrader being considered ready for its intended use effective April 1, 2009 and the SAGD facilities being considered ready for its intended use effective July 1, 2008.
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* Future tax recovery
Future tax expense for the three months ended June 30, 2009 is a recovery of $32 million (2008: $8 million) and for the six months ended June 30, 2009 is a recovery of $25 million (2008: $9 million). Future tax recovery for the six months ended June 30, 2009 is primarily related to the future tax benefit derived from current year losses from operations, net of a valuation allowance in respect of unrealized foreign exchange capital losses on U.S.-dollar- denominated debt. The valuation allowance was partially reversed in the three months ended June 30, 2009 due to a strengthening Canadian dollar relative to the US dollar.
* Foreign exchange hedging instruments
OPTI is exposed to foreign exchange rate risk on our long-term U.S.-dollar-denominated debt. To partially mitigate this exposure, we have entered into US$875 million of foreign exchange forwards to manage our exposure to repayment risk on our U.S.-dollar-denominated debt. The forward contracts provide for the purchase of U.S. dollars and the sale of Canadian dollars at a rate of approximately CDN$1.17 to US$1.00 with an expiry in April 2010. With respect to our U.S.-dollar-denominated debt, these forward contracts provide protection against a decline in the value of the Canadian dollar below CDN$1.17 to US$1.00 on a portion of our debt. As noted under “Liquidity”, the value of these derivatives affects our debt to capitalization covenant as the value of these contracts is included in the measurement of our debt for covenant purposes.
Prior to the expiry of this foreign exchange forward in April of 2010, OPTI intends to extend this forward to a later settlement date. In the event that this forward is extended, there would be no cash settlement until the new maturity of the forward. If we are unable or choose not to extend the term of this forward, we expect to pay or receive based on the mark to market of this contract at the time of its current expiry in April 2010. We would expect to receive (pay) an amount approximately equal to US$8.75 million for each $0.01 that the foreign exchange rate is above (below) CDN$1.17 to US$1.00.
SUMMARY FINANCIAL INFORMATION
| 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||||
In millions (except per share amounts) | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | ||||||||||||||||||||||||
| Revenue | $ | 34 | $ | 29 | $ | 69 | $ | 126 | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||
| Net earnings (loss) | (9 | ) | (97 | ) | (410 | ) | (32 | ) | (29 | ) | (6 | ) | 32 | 11 | ||||||||||||||||||
| Earnings (loss) per share, basic and diluted | $ | (0.04 | ) | $ | (0.50 | ) | $ | (2.09 | ) | $ | (0.16 | ) | $ | (0.14 | ) | $ | (0.03 | ) | $ | 0.16 | $ | 0.06 | ||||||||||
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 second quarter of 2008, we had a $34 million unrealized loss on hedging instruments.
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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 and $105 million realized gain and a $28 million unrealized gain on hedging instruments.
The first and second 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 PSCTM. The second quarter of 2009 is the first quarter when we generated revenue and incurred operating expenditures from the Upgrader. Refer also to explanations above regarding realized and unrealized gains and losses related to foreign exchange translation and hedging instruments.
SHARE CAPITAL
On June 30, 2009, OPTI entered into an agreement to issue 85,720,000 common shares at a price of $1.75 per share. The financing closed on July 14, 2009 for total net proceeds of approximately $142 million. At July 15, 2009, OPTI had 281,749,526 common shares and 5,616,316 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 $8.89 per share. At July 15, 2009, OPTI’s fully diluted shares outstanding were 287,365,842.
LIQUIDITY AND CAPITAL RESOURCES
Capital Resources and Liquidity
At June 30, 2009, we have approximately $341 million of financial resources, consisting of $313 million of cash on hand and $28 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 institutions. 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 June 30, 2009, cash used by operating activities was $64 million, cash provided by financing activities was $235 million and cash used by investing activities was $69 million. These changes, combined with a gain on our U.S.-dollar-denominated cash of $7 million, resulted in an increase in cash and cash equivalents during the period of $95 million.
During the first quarter of 2009, we received significant funding as a result of our working interest sale to Nexen that was completed in January 2009. We received gross proceeds of $735 million. We used $545 million of these proceeds to repay amounts owing on our revolving credit facilities and $85 million as pre-funding of a portion of our 2009 joint venture capital program with Nexen. For the remainder of 2009, working capital, operating cash flow and availability under our revolving credit facilities are expected to fund our capital expenditures.
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With the recently completed equity issuance, we expect our financial resources will provide sufficient financial resources until full production of 72,000 bbl/d is reached for the Project, expected by the end of 2010.
OPTI has cash and unused credit facilities of approximately $341 million as of June 30, 2009. This is prior to the receipt of net proceeds received from the equity issuance of $142 million on July 14, 2009. We expect to use our existing cash balances to significantly reduce the balance of our revolving credit facility during the third quarter.
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 is measured quarterly, commencing in the third quarter of 2009. It requires that this ratio is lower than 2.5:1 commencing for the quarter ended September 30, 2009. The first three measurements of EBITDA for this covenant will annualize EBITDA as measured from July 1, 2009, 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.
OPTI has sufficient financial resources to repay the facility in full to satisfy compliance with this covenant for the quarter ending September 30, 2009. In the fourth and subsequent quarters, our compliance with the covenant as currently structured will depend on our operating performance and commodity prices.
OPTI has commenced discussions with certain key lenders (the Lenders) in the revolving credit facility, including the administrative agent, and we plan to broaden these discussions to include the other members of our banking syndicate with the objective of reaching an agreement to defer and amend this debt to EBITDA covenant prior to it becoming operative. We expect that an amendment of this nature will provide us with greater certainty of meeting this covenant, however, no assurances can be made with respect to reaching any agreement with our Lenders. If we are unable to amend and defer this covenant as described below, then we intend to repay this facility (whether temporarily or permanently) to the extent required to satisfy this covenant or pursue other alternatives to satisfy the covenant, including obtaining a replacement facility or pursuing asset sales.
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 2009 as a substantial portion of our production is hedged. We have hedged 6,000 bbl/d for the remainder of 2009 at a net price of approximately US$76/bbl, which is a substantial portion of our expected 2009 PSC™ sales volume. An additional 500 bbl/d for the remainder of 2009 is hedged with a US$77/bbl swap (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™ 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.
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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 of the asset impairment associated with the working interest sale to Nexen and the $85 million increase to January 1, 2009 opening deficit as a result of new accounting pronouncements effective on that date. At June 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 $14 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 factors, such as 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. Also, 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. 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.
Recent developments in capital markets have restricted our access to new debt and equity. Although we expect our financial resources will provide sufficient financial resources until full production is reached by the end of 2010 based on current production and operating estimates, 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.
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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 Poors (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 downgraded in June 2009, with the outlook changed to rating under review from negative. 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 June 30, 2009, our long term debt increased by $235 million as a result of borrowings on our long term revolving credit facility.
The following table shows our contractual obligations and commitments related to financial liabilities at June 30, 2009.
| In $ millions | Total | Remaining 2009 | 2010 - 2011 | 2012 - 2013 | Thereafter | |||||||||||||||
| Accounts payable and accrued liabilities | $ | 84 | $ | 84 | $ | - | $ | - | $ | - | ||||||||||
Long-term debt (Notes - principal)(1) | 2,035 | - | - | - | 2,035 | |||||||||||||||
Long-term debt (Notes - interest)(2) | 902 | 82 | 328 | 328 | 164 | |||||||||||||||
Long-term debt (Revolving)(3) | 322 | - | 322 | - | - | |||||||||||||||
Capital leases(4) | 71 | 2 | 7 | 6 | 56 | |||||||||||||||
Operating leases and other commitments(5) | 76 | 5 | 20 | 20 | 31 | |||||||||||||||
Contracts and purchase orders(6) | 13 | 13 | - | - | - | |||||||||||||||
| Total commitments | $ | 3,503 | $ | 186 | $ | 677 | $ | 354 | $ | 2,286 | ||||||||||
Notes: |
| (1) | Consists of principal repayments on the Notes in Canadian dollars. |
| (2) | Consists of scheduled interest payments on the Notes in Canadian dollars. |
| (3) | Consists of $322 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. |
| (4) | Consists of our share of future payments under our product transportation agreements with respect to future tolls during the initial contract term. |
| (5) | Consists of our share of payments under our product transportation agreements with respect to future tolls during the initial contract term. |
| (6) | 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. |
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NETBACKS
We have provided below an update to our estimated netback for Phase 1 of the Project that was last updated in our Revised Annual MD&A filed on SEDAR on June 3, 2009. The netback calculation based on US$75 WTI pricing is similar to our most recent update other than with respect to presentation of new commodity price assumptions at US$60 WTI and US$90 WTI.
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.
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Estimated Future Project Post-Payout Netbacks(1)
WTI - US$60(2) | WTI - US$75(3) | WTI - US$90(4) | ||||||||||
$/bbl | $/bbl | $/bbl | ||||||||||
Revenue(1) | $ | 75.51 | $ | 86.33 | $ | 95.44 | ||||||
| Royalties and Corporate G&A | (6.58 | ) | (8.93 | ) | (12.80 | ) | ||||||
Operating costs(5) | ||||||||||||
Natural gas(6) | (3.42 | ) | (3.90 | ) | (4.30 | ) | ||||||
Other variable(7) | (2.76 | ) | (2.77 | ) | (2.77 | ) | ||||||
| Fixed | (12.82 | ) | (12.82 | ) | (12.82 | ) | ||||||
Property taxes and insurance(8) | (3.55 | ) | (3.55 | ) | (3.55 | ) | ||||||
Netback(9) | $ | 46.38 | $ | 54.37 | $ | 59.19 | ||||||
Notes:
| (1) | The per barrel amounts are based on the expected yield for the Project of 57,700 bbl/d of PSC™ 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™, 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™, 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 27 percent of WTI and electricity sales prices of $116.45 per MWh. Revenue includes sale of PSC™, 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. |
| (9) | Figures shown above may not sum due to the effects of rounding. |
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™, 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 $29.13 per barrel of products sold. Using a foreign exchange rate of $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, corporate G&A expenses and interest on our senior secured notes at approximately $54.00 per barrel (US$42.00 per barrel (WTI)) of products sold.
OFF-BALANCE-SHEET ARRANGEMENTS
We have no off-balance-sheet arrangements.
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CRITICAL ACCOUNTING ESTIMATES
Our critical accounting estimates are consistent with those noted in our revised 2008 annual MD&A dated February 24, 2009 filed on SEDAR on June 3, 2009, except as revised below.
Depletion, depreciation and amortization
Depletion on SAGD resource assets is measured over the life of proved reserves on a unit-of-production basis and commences when the facilities are substantially complete and after commercial production has begun. Reserve estimates and the associated future capital can have a significant impact on earnings, as they are a key component to the calculation of depletion. A downward revision in the reserve estimate or an upward revision to future capital would result in increased depletion, reduction of earnings and lower book value of SAGD assets. Major SAGD and Upgrader facilities are depreciated with the unit-of-production method based on the productive capacity of the facilities over 40 years.
ACCOUNTING POLICIES
On January 1, 2009, OPTI adopted CICA Section 3064 “Goodwill and Intangible Assets.” This standard replaces Section 3062 “Goodwill and Other Intangible Assets” and Section 3450 “Research and Development Costs”. The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets are equivalent to the corresponding provisions of International Financial Reporting Standard (IFRS) IAS 38, “Intangible Assets.” Emerging Issues Committee (EIC) 27 “Revenues and Expenditures During the Pre-Operating Period” is no longer applicable for OPTI as we have adopted CICA 3064. Accounting Guidelines (AcG) 11 “Enterprises in the Development Stage” is amended to delete references to deferred costs and to provide guidance on development costs as intangible assets under Section 3064.
As a result of these changes and the adoption of these new standards, OPTI expensed certain previously capitalized costs with retroactive effect on January 1, 2009 with a corresponding increase of $85 million opening deficit. This adjustment is primarily comprised of deferred costs related to SAGD start-up activities ($70 million), translation of OPTI’s U.S.-dollar debt ($167 million), offset by gains related to financial derivatives associated with OPTI’s debt ($145 million) and by a recovery of future tax expense ($23 million).
NEW ACCOUNTING PRONOUNCEMENTS
Credit risk and the fair value of financial assets and financial liabilities
On January 20, 2009 the EIC issued a new abstract EIC 173 “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. This abstract concludes that an entity’s own credit risk and the credit risk of the counterparty should be taken into account when determining the fair value of financial assets and financial liabilities, including derivative instruments.
This abstract is to apply to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. The adoption of this abstract did not impact our financial statements.
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IFRS
The Canadian Accounting Standards Board announced that Canadian Generally Accepted Accounting Principles (GAAP) no longer apply for all publically accountable enterprises as of January 1, 2011. From that date forward, OPTI will be required to report under IFRS as set out by the International Accounting Standards Board (IASB). Any adjustments resulting from a change in policy are applied retroactively with corresponding adjustment to opening retained earnings. OPTI is currently evaluating the impact of these new standards. The implementation of IFRS may result in a significant impact on our accounting policies, measurement and disclosure.
During the second quarter, OPTI commenced preparation of a Preliminary Impact Assessment (PIA) to identify differences between Canadian GAAP and IFRS. This work will be completed in the third quarter and the key deliverable from this assessment will be major accounting policy choices under IFRS and their financial statement impact. The PIA will also provide an assessment of information systems and business process impacts of adopting IFRS.
Business Impact of IFRS
OPTI has recorded a pre-tax loss on disposal of $369 million with respect to the working interest sale to Nexen. Under IFRS this loss would have been significantly higher as all of OPTI’s assets would have been considered impaired under IFRS standards. IFRS permits subsequent recovery of such write downs in future periods to the extent that fair value increases. Therefore, the cumulative effect of the Nexen working interest sale at the date of adoption on January 1, 2011 will depend on a fair value assessment of the assets as of December 31, 2010.
NON-GAAP FINANCIAL MEASURES
The term net field operating margin does not have any standardized meaning according to Canadian GAAP. It is therefore unlikely to be comparable to similar measures presented by other companies. We plan to present this measure on a consistent basis from period to period. We consider net field operating margin to be an important indicator of the performance of our business as a measure of the performance of the Project and our ability to fund interest payments and invest in capital expenditures. The most comparable Canadian GAAP financial measure is loss before taxes. For the three and six months ended June 30, 2009, the following is a reconciliation of loss before taxes to net field operating margin (loss).
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$ millions | Three months ended June 30, 2009 | Six months ended June 30, 2009 | ||||||
| Loss before taxes | $ | (41 | ) | (131 | ) | |||
| Interest, net | 42 | 61 | ||||||
| General and administrative | 7 | 13 | ||||||
| Financing charges | 1 | 1 | ||||||
| Loss on disposal of assets | 1 | 2 | ||||||
| Foreign exchange gain | (171 | ) | (96 | ) | ||||
| Net realized gain on hedging instruments | (11 | ) | (35 | ) | ||||
| Net unrealized loss on hedging instruments | 137 | 115 | ||||||
| Depletion, depreciation and accretion | 7 | 11 | ||||||
| Net field operating margin (loss) | $ | (28 | ) | (59 | ) | |||
Internal Controls over Financial Reporting
The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (ICFR), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The control framework our officers used to design OPTI's ICFR is the Internal Control - Integrated Framework (COSO Framework) published by The Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Under the supervision of the Chief Executive Officer and the Chief Financial Officer, OPTI conducted an evaluation of the effectiveness of our ICFR as at December 31, 2008 based on the COSO Framework. Based on this evaluation, these officers concluded that as of December 31, 2008, OPTI's ICFR provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. We have determined that a material change in our internal controls over financial reporting has occurred on April 1, 2009 as a result of the combined impact of the results of the SAGD and Upgrader operations being reported in Statement of Loss and MD&A. We have implemented controls with respect to measurement and disclosure for petroleum sales, operating costs, diluent and feedstock purchases, transportation costs, interest expense and depletion, depreciation and amortization.
FINANCIAL INSTRUMENTS
The Company considers its risks in relation to financial instruments in the following categories:
Credit Risk
Credit risk is the risk that counterparty to a financial instrument will not discharge its obligations, resulting in a financial loss to the Company. The Company has policies and procedures in place that govern the credit risk it will assume. We evaluate credit risk on an ongoing basis including an evaluation of counterparty credit rating and counterparty concentrations measured by amount and percentage. Our objective is to have no credit losses.
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The primary sources of credit risk for the Company arise from the following financial assets: (1) cash and cash equivalents; (2) accounts receivable; and (3) derivatives contracts. The Company has not had any credit losses in the past and the risk of financial loss is considered to be low given the counterparties used by the Company. As at June 30, 2009, the Company has no financial assets that are past due or impaired due to credit-risk-related defaults.
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet obligations associated with financial liabilities. Our financial liabilities are comprised of accounts payable and accrued liabilities, hedging instruments, long-term debt and obligations under capital leases. The Company frequently assesses its liquidity position and obligations under its financial liabilities by preparing regular financial forecasts. We mitigate liquidity risk by maintaining a sufficient cash balance as well as maintaining sufficient current and projected liquidity to meet expected future payments. Our financial liabilities arose primarily from the development of the Project. As at June 30, 2009, the Company has met all of the obligations associated with its financial liabilities. As noted under “Capital Resources and Liquidity,” continued access to our revolving credit facility is a key liquidity risk.
Market Risk
Market risk is the risk that the fair value (for assets or liabilities considered to be held for trading and available for sale) or future cash flows (for assets or liabilities considered to be held-to-maturity, other financial liabilities, and loans and receivables) of a financial instrument will fluctuate because of changes in market prices. We evaluate market risk on an ongoing basis. We assess the impact of variability in identified market risks on our medium-term cash requirements and impact with respect to covenants on our credit facilities. At June 30, 2009, we had mitigation programs to reduce market risk related to foreign exchange and commodity price changes. The primary market risks related to our commodity contracts relates to future estimated prices for WTI. The estimated change in our net field operating margin with respect to a $5 per barrel change in WTI in the second half of 2009 is not material.
The following sections describe these risks in relation to the Company’s key financial instruments.
* Cash and Cash Equivalents
The Company has cash deposits with Canadian banks and has money market investments. Counterparty selection is governed by the Company’s Treasury Policy, which limits concentration of investments and requires that all instruments be rated as investment grade by at least one rating agency. As at June 30, 2009 the amount in cash and cash equivalents was $313 million and the maximum exposure to a single counterparty was $76 million which is guaranteed by a major Canadian bank.
At June 30, 2009, the remaining terms on investments made by the Company are less than 31 days with interest fixed over the period of investment. Maturity dates for investments are established to ensure cash availability for project development and interest payments. Investments are held to maturity and the maturity value does not deviate with changes in market interest rates.
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Our cash balances are currently invested exclusively in money market instruments with major Canadian banks in the form of banker’s acceptances, banker’s deposit notes or term deposits. These instruments are widely offered by banks we deal with and are considered direct obligations of the banks that offer them. We manage our exposure to these banks in two primary ways: by limiting the amount invested with a single issuer or guarantor and by investing for relatively short periods of time. We do not expect any investment losses based on these money market investments.
* Accounts Receivable
Our accounts receivable includes amounts due from Nexen Inc. related to project development and Nexen Marketing related to marketing activities, and amounts due from the Canada Revenue Agency in relation to GST refunds. Our accounts receivable due from Nexen includes $7 million related to operating activities. The Company’s credit risk in regard to accounts receivable therefore relates primarily to the risk of default by Nexen, which has an investment-grade corporate rating from Moody’s Investor Service, and by financial institutions with an investment grade rating. Therefore, we estimate our risk of credit loss as low.
* Accounts Payable and Accrued Liabilities
As at June 30, 2009, accounts payable and accrued liabilities were $84 million. Accounts payable and accrued liabilities are comprised primarily of $69 million due in respect of development and operation of the Project, $7 million due in respect of interest on our Notes and $8 million related to corporate expenses including hedging instruments. Payment terms on development and operation of the Project are typically 30 to 60 days from receipt of invoice and generally do not bear interest. Payments are due on the notes semi-annually in June and December. The Company has met its obligations in respect of these liabilities.
* Debt and Obligations under Capital Lease
As at June 30, 2009, long-term debt was $2,357 million, short-term debt was $nil and obligations under capital leases were $21 million. The terms of the Company’s debt and obligations under capital lease are described in the notes to our financial statements as at June 30, 2009. The Company has met its obligations in respect of these liabilities. The Company accounts for its borrowings under all of its long-term debt and obligations under capital lease on an amortized cost basis.
The revolving credit facility is a variable interest rate facility with borrowing rates and duration established at the time of the initial borrowing or subsequent extension. Our current borrowings have an approximate initial term of 30 - 90 days and therefore fluctuations in the value of such borrowings are not material during the term they are outstanding. The Company is exposed to interest rate changes if and when it extends each borrowing. The extent of the exposure to interest rate risk depends on the amount outstanding under the facility. As at June 30, 2009, there was $322 million drawn under the revolving credit facility. During the second quarter of 2009, a 1 percent change in market interest rates would not have had a material impact on the interest expense due to the fixed nature of our senior notes and relatively low average balance of our revolving credit facilities.
Our Notes are comprised of US$1,750 million of debt which has fixed U.S. dollar semi-annual interest payments. Changes in the exchange rate between the Canadian dollar and U.S. dollar impact the carrying value of the Notes. A US$0.01 change in the exchange rate will impact the carrying value of the Notes by approximately US$18 million. A US$0.01 change in the exchange rate will change our annual interest costs by approximately US$1.4 million. The exposure to exchange rate fluctuations has been partially mitigated by the forward contracts described under “Foreign Exchange Hedging Instruments.” These changes also influence our compliance with debt covenants as described under ”Capital Resources and Liquidity.”
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* Derivative Contracts
The Company periodically uses derivative contracts to hedge certain of the Company’s projected operational or financial risks. In the past, such instruments have involved the use of interest rate swaps, cross-currency interest swaps, currency-forward contracts and crude oil put options and swaps. Derivative contracts outstanding are described in the notes to our financial statements as at June 30, 2009. These instruments are designated as held-for-trading and are measured at fair value at each financial statement date.
As at June 30, 2009, we had US$875 million of foreign currency forwards to manage a portion of the exposure to the foreign exchange variations on the Company’s long-term debt. Changes in the exchange rate between Canadian and U.S. dollars change the value of these instruments. The foreign currency forwards at June 30, 2009, had a fair value of negative $14 million. The foreign exchange forwards are measured by the present value of the difference between the settlement amounts of the foreign currency forwards as measured in Canadian dollars. The counterparties to the foreign currency forwards are major Canadian and international banks. Our exposure to non-payment from any single institution is less than 25 percent of the value of the forwards.
The fair value of the foreign currency forwards is determined by calculating the present value of the existing contract as measured in Canadian dollars in reference to established market rates, primarily foreign exchange rates at the end of the year and discounted at market interest rates. The foreign currency forwards were valued primarily using a period-end foreign exchange rate of CDN$1.16 to US$1.00. Based on the active market for the underlying market variables used in the valuation, we do not believe other market assumptions with respect to these variables could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal comparison completed by OPTI to compare the valuation provided by each counterparty to the forwards. The value of the foreign currency forwards would change by approximately $8 million for each $0.01 change in the foreign exchange rate between U.S. and Canadian dollars. This change would have a corresponding impact on earnings (loss) before taxes in 2009.
We have established commodity hedging contracts to mitigate the Company’s exposure of future operations to decreases in the price of its synthetic crude oil. The Company has chosen to use put options and commodity price swaps to mitigate a portion of the exposure. As at June 30, 2009 the Company had deferred premium put options covering 1.2 million barrels of remaining 2009 production at a price of US$80/bbl (deferred premiums to be paid on the expiration of the option are $4/bbl); and commodity price swaps covering 0.09 million barrels of remaining 2009 production at a price of US$77/bbl. The value of these financial instruments as at June 30, 2009 was an asset of $15 million. In addition, we have entered into swap options that provide for 1.1 million barrels at strike prices between US$64 and US$67 per barrel of crude oil starting January 1, 2010 through December 31, 2010. The value of these financial instruments as at June 30, 2009 was a liability of $12 million. The counterparties to the commodity hedges are major Canadian and international banks. Our exposure to non-payment from any single institution is approximately 60 percent of the value of the commodity asset, which is due from a major Canadian bank.
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The fair value of the commodity hedges is determined by calculating the present value of the existing contract as measured in Canadian dollars in reference to established market rates, primarily future estimated prices for WTI and period-end foreign exchange rates. Based on the active market for the underlying market variables used in the evaluation, we do not believe other market assumptions with respect to these variables could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal comparison completed by OPTI to compare the valuation provided by each counterparty to the contract. The value of the commodity hedges would change by approximately US$2 million for each US$1/bbl change in future estimated prices for WTI. This change would have a corresponding impact on our earnings (loss) before taxes.
We view the credit risk of these counterparties as low due to the diversification of the instrument with a number of banks.
RISK FACTORS
Our risk factors are consistent with our 2008 revised MD&A dated February 24, 2009 and filed on SEDAR on June 3, 2009, except as amended below.
Revolving Credit Facility Covenant Risk
Continued access to our revolving credit facility is critical to support our ongoing financial position as described more completely under “Capital Resources and Liquidity” Failure to comply with our total debt to capitalization and revolving credit facility debt to EBITDA covenants would entitle the lenders to accelerate the loan maturity and proceed with enforcement of the revolver lender’s security. The primary risks of failure to meet this covenant in 2009 are low or unstable bitumen production, low or unstable Upgrader operation and higher than planned operating and capital costs.
In respect of new borrowings under the $350 million revolving credit facility, we are subject to various conditions precedent including the absence of any material adverse effect and, prior to reaching completion of the ramp-up to substantial production, a requirement to have sufficient funds (including cash and undrawn amounts under the revolving credit facility) to fund our share of remaining Project costs. Although the credit facility is substantially drawn and we are currently able to meet this sufficient funding requirement, no assurance can be made that we will be able to meet these conditions precedent at the time of any future drawdown.
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