Exhibit 99.1
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the three months ended
March 31, 2010
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis (MD&A), dated April 28, 2010, should be read in conjunction with the audited financial statements and accompanying MD&A for the year ended December 31, 2009 and the unaudited financial statements for the three months ended March 31, 2010.
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) and significant increase thereof; OPTI Canada Inc.’s (OPTI or the Company) 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); t he timing of OPTI’s wells coming on production; the expected SOR of wells; the expected increase in on-stream time average during 2010; the anticipated amount of externally-sourced bitumen OPTI will purchase in 2010; expected increase in Premium Sweet Crude (PSC™) yields; the ability of OPTI to achieve positive net field operating margin later in 2010; expected increase in the PSC™ premium OPTI receives relative to other synthetic crude oils; ability of the Company to extend its remaining currency forwards; expected business impact of International Financial Reporting Standards (IFRS) on OPTI’s financial statements; OPTI’s financial outlook; OPTI’s anticipated financial condition and liquidity over the next 12 months and in the long term; and our estimated future tax asset. Forward-looking information typically contains statements with words such as “intends,” “anticipate,” “es timate,” “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 th ose 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™ and Premium Synthetic Heavy (PSH); 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.
FINANCIAL HIGHLIGHTS
| | | Three months ended March 31 | | | Years ended December 31 | |
In millions | | 2010(1) | | | 2009(1) | | | 2008(2) | |
| | | | | | | | | | | | | |
| Net earnings (loss) | | $ | (50 | ) | | $ | (306 | ) | | $ | (477 | ) (3) |
| | | | | | | | | | | | | |
| Working capital (deficiency) | | | 23 | | | | 168 | | | | (25 | ) |
| | | | | | | | | | | | | |
Total oil sands expenditures (4) | | | 30 | | | | 148 | | | | 706 | |
| | | | | | | | | | | | | |
| Shareholders’ equity | | $ | 1,261 | | | $ | 1,311 | | | $ | 1,471 | |
| | | | | | | | | | | | | |
Common shares outstanding (basic) (5) | | | 282 | | | | 282 | | | | 196 | |
Notes:
| (1) | Amounts for 2010 and 2009 represent our 35 percent working interest in the Project. |
| | |
| (2) | Amounts for 2008 represent our then 50 percent working interest in the Project. |
| | |
| (3) | Includes $369 million pre-tax asset impairment provision related to working interest sale to Nexen. |
| | |
| (4) | Capital expenditures related to Phase 1 and future phase development. Capitalized interest, hedging gains/losses and non-cash additions or charges are excluded. |
| | |
| (5) | Common shares outstanding at March 31, 2010 after giving effect to the exercise of stock options would be approximately 284 million common shares. |
PROJECT STATUS
The following update was provided in our press release dated April 27, 2010.
Continued ramp up of steam injection and bitumen production rates remained the focus of our operations at the Long Lake Project (the Project) in the first quarter of 2010.
Bitumen production is rising and the reservoir is responding to consistent steam injection. This trend has continued since the turnaround completed in the fall of 2009. During the first quarter of 2010 bitumen production averaged approximately 18,700 barrels per day (bbl/d) (6,545 bbl/d net to OPTI), a significant increase over the fourth quarter of 2009 average of approximately 13,600 bbl/d (4,760 bbl/d net to OPTI). March bitumen production averaged 22,000 bbl/d and recent production is approximately 25,000 bbl/d (8,750 bbl/d net to OPTI).
Steam assisted gravity drainage (SAGD) surface facilities continue to perform reliably and as per design following the turnaround. Steam injection rates increased in the first quarter of 2010 to average approximately 114,000 bbl/d as compared to 76,000 bbl/d in the previous quarter. Steam injection rates continue to rise, with recent all-time highs of approximately 140,000 bbl/d. We currently have 79 well pairs receiving steam, comprised of 64 wells pairs on production and an additional 15 well pairs in circulation mode. With the conversion of wells from circulation to production mode, we expect nearly all of our available wells to be on product ion over the next few months.
Our recent all-in steam-to-oil ratio (SOR) average is between 5 and 6, including steam to wells that are currently in steam circulation mode and wells early in the ramp up cycle. The recent SOR average of our producing wells is approximately 5 and includes 12 well pairs converted to production mode during the first quarter of 2010. As new production wells progress further along in the production cycle we would expect bitumen production to rise and corresponding SOR to decrease. During bitumen ramp up, the SOR for both all-in and producing wells is expected to be higher than our long term estimate of 3.0. We expect SOR to decline during 2010 as we maintain reliable steam injection.
Upgrader units continue to perform consistently. On-stream time averaged 78% in the first quarter of 2010 and 87% in March; this measure is expected to increase during 2010. Throughout the SAGD ramp up period, we expect to purchase approximately 10,000 bbl/d of externally-sourced bitumen. We continue to use produced syngas as a low cost fuel source in our SAGD operations. Premium Sweet Crude (PSCTM) yields averaged approximately 63% over the first quarter of 2010 as compared with 60% in the previous quarter. Yield for the first quarter of 2010 was temporarily affected by down-time in the solvent deasphalter during February but was higher in the remainder of the quarter. Yields are expected to increase to the design rate of 80% once the Upgrader consistently reaches approximately 50% of design capacity, including externally-sourced bitumen.
FUTURE PHASES
Phase 2 engineering and initial development of Phases 3 through 6 continue.
STRATEGIC ALTERNATIVES REVIEW
The following update was provided in our press release dated April 27, 2010.
OPTI’s Board of Directors continues to move forward in its process to explore strategic alternatives for enhancing shareholder value. The economic environment, recent operational improvements, strengthening merger and acquisition valuations for oil sands assets and the future potential of OPTI’s assets support its current strategy. Strategic alternatives may include capital market opportunities, restructuring the current credit facility, asset divestitures, and/or a corporate sale, merger or other business combination. The ultimate objective of carrying out this review is to determine which alternative(s) might result in superior value for shareholders.
RESULTS OF OPERATIONS
| | | Three months ended March 31 | |
$ millions, except per share amounts | | 2010 | | | 2009 | |
| Revenue, net of royalties | | $ | 50 | | | $ | 29 | |
| Expenses | | | | | | | | |
| Operating expense | | | 52 | | | | 28 | |
| Diluent and feedstock purchases | | | 23 | | | | 29 | |
| Transportation | | | 4 | | | | 3 | |
| Net field operating margin (loss) | | | (29 | ) | | | (31 | ) |
| Corporate expenses | | | | | | | | |
| Interest, net | | | 49 | | | | 19 | |
| General and administrative | | | 4 | | | | 6 | |
| Realized loss (gain) on hedging instruments | | | 4 | | | | (24 | ) |
| Earnings (loss) before non-cash items | | | (86 | ) | | | (32 | ) |
| Non-cash items | | | | | | | | |
| Foreign exchange translation loss (gain) | | | (72 | ) | | | 75 | |
| Net unrealized loss (gain) on hedging instruments | | | 26 | | | | (22 | ) |
| Depletion, depreciation and accretion | | | 10 | | | | 4 | |
| Loss on disposal of assets | | | — | | | | 1 | |
| Future tax expense (recovery) | | | — | | | | 7 | |
| Net earnings (loss) | | $ | (50 | ) | | $ | (97 | ) |
| Earnings (loss) per share, basic and diluted | | $ | (0.18 | ) | | $ | (0.50 | ) |
First Quarter Operational Overview
The results of operations for the first quarter of 2010 include SAGD and Upgrader results. The results for the same period in 2009 only include SAGD results. We determined the Upgrader to be ready for its intended use for accounting purposes on April 1, 2009. Revenue for the first quarter of 2010 was a combination of PSCTM, Premium Synthetic Heavy (PSH) and power sales where as revenue for the same period in 2009 consisted of PSH and power sales.
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 $29 million for the first quarter of 2010 as compared with a loss of $31 million during the same period in 2009. The net field operating loss in 2010 includes SAGD and Upgrader operations whereas 2009 includes only SAGD operations. Although our net field operating margin was a loss in the first quarter of 2010, we achieved improvements each month in our production volumes and net field operating margin. We anticipat e that increased production and other operating improvements will lead to a positive net field operating margin later this year.
On-stream factor is a measure of the period of time that the Upgrader is producing PSC™ and it is calculated as the percentage of hours the Hydrocracker Unit in the Upgrader is in operation. When the Upgrader is not in operation, results are adversely affected by the requirement to purchase diluent, which is blended with bitumen to produce and sell PSH. PSH revenue per barrel is lower than PSC™ revenue per barrel. The majority of SAGD and Upgrader operating costs are fixed, so 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™ sales and lower d iluent costs. PSC™ yield represents the volume percentage of PSC™ generated from processing bitumen through the Upgrader.
The Upgrader on-stream factor for the first quarter of 2010 was 78% as compared to 56% in the fourth quarter of 2009. PSC™ yield for the first quarter of 2010 was 63% as compared to 60% in the fourth quarter of 2009. PSC™ yield for the first quarter of 2010 was temporarily affected by down-time in the solvent deasphalter during February but was higher in the remainder of the quarter. Our share of PSC™ sales increased to 3,500 bbl/d in the first quarter of 2010 compared to 3,000 bbl/d in the in the fourth quarter of 2009 while our share of PSH sales increased to 3,500 bbl/d in the first quarter of 2010 from 3,300 bbl/d in the fourth quarter of 2009. As a result of the increased on-stream factor and the use of our own PSC™ to blend with bitumen for PSH, diluent purchases in the first quarter of 2010 declined to $1 million from $7 million in the fourth quarter of 2009.
Revenue
For the first quarter of 2010 we earned revenue net of royalties of $50 million compared to $29 million for the same period in 2009. During the first quarter of 2010, our share of PSC™ sales averaged 3,500 bbl/d at an average price of approximately $82/bbl whereas in the first quarter of 2009, our PSC™ sales were all capitalized as the Upgrader was not deemed ready for its intended use for accounting purposes. For the first quarter of 2010 our share of PSH averaged 3,500 bbl/d (first quarter of 2009: 7,700 bbl/d) at an average price of approximately $72/bbl (first quarter of 2009: $40/bbl). Our share of bitumen production in the first quarter of 2010 averaged 6,500 bbl/d (first quarter of 200 9: 4,700 bbl/d). Our total revenue, net of royalties, diluent and feedstock increased to $27 million for the first quarter of 2010 compared to nil for the same period in 2009. This is primarily due to higher PSC™ sales in 2010 as a result of a higher Upgrader on-stream factor in 2010.
In the first quarter of 2010 we received pricing for PSCTM in-line with, or better than, other synthetic crude oils. Due to the premium characteristics of our PSCTM, we expect the premium we receive relative to other synthetic crude oils to increase as the production and availability of marketed PSCTM increases.
For the first quarters of 2010 and 2009 we had power sales of $2 million. In the first quarter of 2010 this represented approximately 48,700 megawatt hours (MWh) of electricity sold at an average price of approximately $42/MWh compared to the same period in 2009 which represented 23,500 MWh at a price of $70/MWh.
Expenses
* Operating expenses
Our operating expenses are primarily comprised of natural gas, maintenance, labour, operating materials and services.
For the first quarter of 2010 operating expenses were $52 million compared to $28 million for the same period in 2009. Operating expenses in 2010 are higher as they included SAGD results as well as Upgrader results, whereas operating expenses in 2009 only included SAGD results. There were no Upgrader operating expenses in 2009 since these costs were capitalized because the Upgrader was not considered to be ready for its intended use for accounting purposes.
* Diluent and feedstock purchases
For the first quarter of 2010 diluent and feedstock purchases were $23 million compared to $29 million for the same period in 2009. In the first quarter of 2010 diluent purchases were $1 million which represented approximately 230 bbl/d of diluent at an average price of $82/bbl compared to the first quarter of 2009 purchases of $21 million which represented approximately 4,100 bbl/d at an average price of $56/bbl. Diluent purchases decreased for the first quarter of 2010 compared to the same period in 2009 due to a higher Upgrader on-stream factor in 2010 and the use of a portion of our own PSCTM as diluent for PSH sales.
In the first quarter of 2010 we purchased $22 million of third party bitumen representing approximately 3,800 bbl/d compared to $8 million representing approximately 2,300 bbl/d for the same period in 2009. The increase in third party bitumen purchases in 2010 is due to a higher on-stream factor of the Upgrader.
* Transportation
For the first quarter of 2010 transportation expenses were $4 million compared to $3 million for the same time period in 2009. Transportation expenses were primarily related to pipeline costs associated with PSCTM and PSH sales. The increase in transportation expenses in 2010 was a result of the increase in pipeline volume commitments.
Corporate expenses
* Net interest expense
For the first quarter of 2010 net interest expense was $49 million compared to $19 million for the same period in 2009. The increase in net interest expense was primarily due to interest expense in the first quarter of 2010 including interest related to the SAGD facilities as well as interest costs related to the Upgrader, whereas interest expenses for the same period in 2009 only included interest related to the SAGD facilities. Net interest expense in the 2009 period included interest on amounts owing on the revolving credit facility whereas in 2010 interest expense includes interest costs on the US$425 million First Lien Notes that were issued in November 2009 but not on the revolving credit facility as it remained undrawn during the first quarter of 2010. This increase was partially offset by lower Canadian interest costs on our U.S. dollar-denominated debt due to a stronger Canadian dollar in the first quarter of 2010 compared to the same period in 2009.
* General and Administrative (G&A) Expense
For the first quarter of 2010 G&A expense was $4 million, compared to $6 million for the same period in 2009. Included in G&A expense for the first quarter of 2010 was $1 million related to the strategic alternative process. G&A expense was lower in the first quarter of 2010 due to severance payments during the same period in 2009 related to the re-organization of OPTI after the working interest sale to Nexen. Included in G&A expense is a stock-based compensation expense of $0.4 million (first quarter of 2009: $0.5 million).
* Net realized gain or loss on commodity hedging instruments
For the first quarter of 2010 net realized loss on hedging instruments was $4 million compared to a gain of $24 million for the same period in 2009. This $4 million loss relates to 2010 commodity hedging instruments for 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl. The gains in the first quarter of 2009 were related to our US$80/bbl crude oil puts and our US$77/bbl crude oil hedging instruments.
Non-cash items
* Foreign exchange gain or loss
For the first quarter of 2010 foreign exchange translation was a $72 million gain compared to a $75 million loss for the same period in 2009. The gain or loss is comprised of the re-measurement of our U.S. dollar-denominated long-term debt and cash. For the first quarter of 2010 the Canadian dollar strengthened from CDN$1.05:US$1.00 to CDN$1.02:US$1.00, resulting in a foreign exchange translation gain for the period. For the same period in 2009 the Canadian dollar weakened from CDN$1.22:US$1.00 to CDN$1.26:US$1.00 resulting in a foreign exchange translation loss. These gains and losses are unrealized.
* Net unrealized gain or loss on hedging instruments
For the first quarter of 2010 net unrealized loss on hedging instruments was $26 million, compared to a $22 million gain for the same period in 2009. The net unrealized loss in 2010 is comprised of a $28 million unrealized loss on our foreign exchange hedges due to the strengthening of the Canadian dollar from CDN$1.05:US$1.00 to CDN$1.02:US$1.00 and a $2 million unrealized gain on our commodity hedges due to the maturing of the instruments during the quarter offset by the increase in the future price of WTI from approximately US$75/bbl at the beginning of the quarter to approximately US$81/bbl at March 31, 2009. The gain in the first quarter of 2009 was due to a $37 million increase in the fair value of our foreign exchange hedges due to a weakening Canadian dollar offset by a $15 million decrease in the fair value of our commodity hedges as the future price of WTI increased during the quarter.
* Depletion, depreciation and amortization (DD&A)
For the first quarter of 2010 DD&A was $10 million, compared to $4 million for the same period in 2009. DD&A for the first quarter of 2010 is depletion and depreciation for both SAGD facilities and Upgrader facilities whereas for the first quarter of 2009 DD&A was depletion and depreciation of the SAGD facilities only.
* Loss on disposal of assets
For the first quarter of 2010 loss on disposal of assets was nil compared to $1 million for the same period in 2009. The loss on disposal of assets for the same period in 2009 was primarily for costs incurred related to the asset sale to Nexen during the quarter.
* Future tax expense
For the first quarter of 2010 future tax expense was nil compared to $7 million for the same period in 2009. For the first quarter of 2010, based on the recurrence of net field operating losses, we determined we do not meet the “more likely than not” criteria required for recognition of future tax assets and have therefore recognized a valuation allowance against our future tax assets. We will assess the need for this valuation allowance each reporting period.
CAPITAL EXPENDITURES
The table below identifies expenditures incurred by us in relation to the Project, other oil sands activities and other capital expenditures.
| $ millions | | Three months ended March 31, 2010 | | | Year ended 2009 | | | Year ended 2008 | |
| Long Lake Project – Phase 1 | | | | | | | | | |
| Upgrader & SAGD | | $ | 2 | | | $ | 20 | | | $ | 480 | |
| Sustaining capital | | | 22 | | | | 63 | | | | 60 | |
| Capitalized operations | | | — | | | | 19 | | | | 32 | |
| Total Long Lake Project | | | 24 | | | | 102 | | | | 572 | |
| Expenditures on future phases | | | | | | | | | | | | |
| Engineering and equipment | | | 5 | | | | 21 | | | | 64 | |
| Resource acquisition and delineation | | | 1 | | | | 25 | | | | 70 | |
| Total oil sands expenditures | | | 30 | | | | 148 | | | | 706 | |
| Capitalized interest | | | — | | | | 29 | | | | 139 | |
| Other capital expenditures | | | — | | | | (19 | ) | | | 45 | |
| Total cash expenditures | | | 30 | | | | 158 | | | | 890 | |
| Non-cash capital charges | | | — | | | | — | | | | 11 | |
| Total capital expenditures | | $ | 30 | | | $ | 158 | | | $ | 901 | |
Capital expenditures for the first quarter of 2010 and for the year ended December 31, 2009 represent our 35 percent working interest in the Project whereas capital expenditures for the year ended December 31, 2008 represent our then 50 percent working interest.
For the first quarter of 2010 we incurred capital expenditures of $30 million. Phase 1 Upgrader and SAGD expenditures of $2 million were primarily related to the commissioning and start-up of the steam expansion project, which was complete at quarter-end, and commissioning of train 4 of the gasifier. Completion of the steam expansion project is expected to allow further steam generation ramp up and the train 4 gasifier is anticipated to improve Upgrader reliability.
As with all SAGD projects, new well pads must be drilled and tied-into the SAGD central facility to maintain production at design rates over the life of the Project. For the first quarter of 2010 we had sustaining capital expenditures of $22 million. These capital expenditures included the following allocations. Our investment in resource delineation for future Phase 1 well pads, including coreholes and four-dimensional seismic and the tie-in of two water source wells; and the installation of 11 electric submersible pumps in producing wells for better well control and enhanced bitumen extraction; and oil removal filters for oil and particulate removal from the produced water stream for improved water tre atment. We also commissioned pad 11 and commenced construction on another two well pads.
For the first quarter of 2010 we incurred expenditures of $5 million for engineering and $1 million for resource delineation for future phases. Resource delineation for future phases includes lease acquisitions and other delineation activities.
SUMMARY FINANCIAL INFORMATION
In millions (unaudited) (except per share amounts) | | 2010 | | | 2009 | | | 2008 | |
| | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | |
| Revenue | | $ | 50 | | | $ | 43 | | | $ | 38 | | | $ | 34 | | | $ | 29 | | | $ | 69 | | | $ | 126 | | | $ | — | |
| Net earnings (loss) | | | (50 | ) | | | (212 | ) | | | 12 | | | | (9 | ) | | | (97 | ) | | | (410 | ) | | | (32 | ) | | | (29 | ) |
| Earnings (loss) per share, basic and diluted | | $ | (0.18 | ) | | $ | (0.75 | ) | | $ | 0.04 | | | $ | (0.04 | ) | | $ | (0.50 | ) | | $ | (2.09 | ) | | $ | (0.16 | ) | | $ | (0.14 | ) |
Quarterly results for 2010 and 2009 represent our 35 percent working interest in the Project, whereas quarterly results for 2008 represent our then 50 percent working interest.
Prior to the third quarter of 2008, earnings were 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.
In the third and fourth quarters of 2008, we generated revenue and incurred operating expenditures associated with early stages of SAGD operation. During the third quarter of 2008, we had a $64 million unrealized gain on hedging instruments offset by a $73 million dollar foreign exchange loss. 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 of $116 million primarily related to this impairment, a $254 million foreign exchange translation loss, and $105 million realized gain as well as a $28 million unrealized gain on hedging instruments.
Operations during 2009 and 2010 represent initial stages of our operations at relatively low operating volumes. Our operating results associated with these activities are expected to improve as SAGD production increases and the Upgrader produces higher volumes of PSCTM.
Net loss of $97 million in the first quarter of 2009 was associated with operating expenses in the early stages of SAGD operations that operated at relatively low volumes which lead to a net field operating loss of $31 million. In addition, we had a $75 million foreign exchange loss offset by a net realized and unrealized gain on hedging instruments of $46 million. Net earnings of $12 million in the third quarter of 2009 were 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. The net loss of $212 million in the fourth quarter for 2009 includes a net field operating loss of $21 million, interest expense of $43 million, an unrealized loss on our hedges of $36 million offset by a foreign exchange gain of $36 million, and a future tax expense of $119 million that resulted from the recognition of a future tax asset valuation allowance.
During the third quarter of 2009 OPTI issued 86 million common shares increasing the total issued and outstanding shares from approximately 196 million to 282 million. This reduces our earnings or loss per share by approximately 30 percent in the quarters subsequent to this common share issuance.
During the first quarter of 2010 we had a net field operating loss of $29 million, $49 million in interest expenses and a $26 million unrealized loss on hedging instruments offset by a foreign exchange gain of $72 million.
SHARE CAPITAL
At April 28, 2010, OPTI had 281,749,526 common shares and 2,708,500 common share options outstanding. The common share options have a weighted average exercise price of $4.65 per share.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2010, we had approximately $462 million of financial resources, consisting of $272 million of cash on hand and a $190 million undrawn revolving credit facility. Our cash and cash equivalents are invested exclusively in money market instruments issued by major Canadian banks. Our long-term debt consists of US$1,750 million of Secured Notes and US$425 million First Lien Notes (collectively, our “Senior Notes”) and a $190 million undrawn revolving credit facility.
Expected remaining cash outflows for 2010 include approximately $90 million of the total capital budget of $119 million. In addition, annual interest payments of US$180 million are due with respect to our Senior Notes. Our financial resources will also be affected by net field operating margin. Our net field operating margin was a loss of $29 million in the first quarter of 2010. In order for the net field operating margin to become positive in 2010, some or all of the following will be required: a continued increase in bitumen volumes; stable or increasing on-stream factor; stable or increasing commodity prices (in particular, WTI); a PSC™ yield approaching our design rate of 80%; and stable opera ting costs. Based primarily on our expectation of a significant increase in bitumen production and extension of our remaining foreign exchange currency forwards, we expect our financial resources are sufficient to meet our obligations through the remainder of 2010.
As of April 16, 2010, OPTI has extended $75 million of its $330 million foreign exchange currency forwards originally maturing in April 2010. The remaining $255 million of foreign exchange forwards maturing in April 2010 were settled by a cash payment of $44 million. Including the foreign exchange currency forwards that had previously been extended in the fourth quarter of 2009, we have $620 million of foreign exchange forwards outstanding at an average rate of CDN$1.19:US$1.00 with a maturity date of December 2010. OPTI intends to extend these remaining foreign exchange forward contracts past the maturity dates in December 2010. If the contracts cannot be extended the resulting cash settlement will be a function of the foreign exchange rate in effect at the maturity date. The cash settlement of our remaining foreign exchange forward at the March 31, 2010 foreign exchange rate of CDN$1.02:US$1.00 would be $105 million. The actual future cash settlement could be materially different, as a $0.01 change in the foreign exchange rate will affect this obligation by approximately $6 million.
For the first quarter of 2010 cash used by operating activities was $43 million, cash used by financing activities was $8 million and cash used by investing activities was $29 million. These cash flows, combined with a translation loss on our U.S. dollar denominated cash of $6 million, resulted in a decrease in cash and cash equivalents during the period of $86 million.
During the first quarter of 2010 we used our existing cash to fund our capital expenditures and operational activities. In the remainder of 2010 our primary sources of funding include our existing cash and our undrawn revolving credit facility.
We have initiated a process to explore strategic alternatives for enhancing shareholder value. This process is designed to assess a range of strategic alternatives that may include capital markets opportunities, restructuring the current credit facility, asset divestitures, and/or a corporate sale, merger or other business combination. A primary objective of this process is to reduce our overall leverage and position the Company for future phase development. If a transaction is completed in 2010, it would be expected to have a material impact on our liquidity and capital resources. There can be no assurance that any transaction will occur or, if a transaction is undertaken, as to its terms or timing.
Our rate of production increase will have a significant impact on our financial position through 2010 and beyond. Our net field operating margin in the first quarters of 2010 and 2009 is a loss. It is important for our business to increase production to a point where we generate positive net field operating margins. Failure to improve bitumen production rates, and ultimately PSCTM sales, will result in continued net field operating losses and difficulty in obtaining new sources of debt and equity.
If production levels and rates-of-increase in 2010 are less than expected, or we are required to settle our remaining foreign exchange currency forwards at unfavourable foreign exchange rates, we may determine that we require additional capital to maintain adequate liquidity.
For 2010 we have mitigated our exposure to commodity pricing as we have hedged 3,000 bbl/d with fixed price 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”). The majority of our operating and interest costs are fixed. Aside from changes in the price of natural gas, our operating 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. Collectively, this means that the variability of our finan cial resources will primarily be influenced by production rates and resulting PSCTM sales, operating expenses and by foreign exchange rates.
Our revolving credit facility requires adherence to a debt to capitalization covenant that does not allow our debt to capitalization ratio to exceed 70 percent, as calculated on a quarterly basis. The ratio 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 book value of equity 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 to exclude the $85 million increase to the January 1, 2009 opening deficit as a result of new accounting pronouncements effect ive on that date. Accordingly, at March 31, 2010, for the purposes of this ratio calculation, our debt would be increased by the amount of our foreign exchange forward liability in the amount of $143 million and our deficit would be reduced by $455 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. The total debt to capitalization calculation for the first quarter of 2010 is 58 percent.
In respect of each new borrowing under the $190 million revolving credit facility, we must satisfy certain conditions precedent prior to making a new borrowing. These include confirmations 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 Senior 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 2009 reserve report, we have sufficient capacity under this test to incur additional debt beyond our existing $190 million revolving credit facility and existing Senior Notes. Other leverage considerations, such as debt restrictions under the Senior Notes and $190 million revolving credit facility, are expected to be more constraining than this limitation.
We have annual interest payments of US$38 million each year until maturity of the US$425 million First Lien Notes in 2012 and annual interest payments of US$142 million each year until maturity of the US$1,750 million Secured 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. The development of future phases will require significant financial resources. We expect to require additional financial resources to de velop the future phases.
Access to capital markets for new equity and debt 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 or inability to extend foreign exchange currency forwards could result in additional funding requirements earlier than we have estimated. Should the Company require any additional funding, it may be difficult to obtain.
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 | | Caa2 | | B- |
| Revolving Credit Facility | | B1 | | B+ |
| First Lien Notes - $425 million | | B2 | | B+ |
| Secured Notes - $1,000 million | | Caa3 | | B |
| Secured Notes - $750 million | | Caa3 | | B |
For the first quarter of 2010 there was no change in the credit ratings from Moody’s or S&P and a negative outlook continues by both rating agencies.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
During the first quarter of 2010 the measurement amount of our long term debt decreased by $75 million due to a lower Canadian dollar equivalent amount for our Senior Notes (principal and interest) associated with a stronger Canadian dollar.
The following table shows our contractual obligations and commitments related to financial liabilities at March 31, 2010.
| In $ millions | | Total | | | 2010 | | | 2011 – 2012 | | | 2013 – 2014 | | | Thereafter | |
Accounts payable and accrued liabilities(1) | | $ | 69 | | | $ | 69 | | | $ | — | | | $ | — | | | $ | — | |
Long-term debt (Senior Notes - principal)(2) | | | 2,210 | | | | — | | | | 432 | | | | 1,778 | | | | — | |
Long-term debt (Senior Notes - interest)(3) | | | 839 | | | | 186 | | | | 365 | | | | 288 | | | | — | |
Capital leases(5) | | | 67 | | | | 2 | | | | 6 | | | | 6 | | | | 53 | |
Operating leases and other commitments(5) | | | 69 | | | | 8 | | | | 20 | | | | 15 | | | | 26 | |
Contracts and purchase orders(6) | | | 5 | | | | 5 | | | | — | | | | — | | | | — | |
| Total commitments | | $ | 3,259 | | | $ | 270 | | | $ | 823 | | | $ | 2,087 | | | $ | 79 | |
| | (1) | Excludes accrued interest expense related to the Senior Notes. These costs are included in (3). |
| | (2) | Consists of principal repayments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.02 to US$1.00 as at March 31, 2010. |
| | (3) | Consists of scheduled interest payments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.02 to US$1.00 as at March 31, 2010. |
| | (4) | As at March 31, 2010, we have an undrawn $190 million revolving credit facility. 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. We do not consider such amounts material. |
| | (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 commitments associated with contracts and purchase orders in connection with the Long Lake Project and our other oil sands activities associated with future phases. |
OFF-BALANCE-SHEET ARRANGEMENTS
We have no off-balance-sheet arrangements.
TRANSACTIONS WITH RELATED PARTIES
We have no transactions with related parties.
CONTROLS AND PROCEDURES
Internal Control over Financial Reporting
The Chief Executive Officer and the Chief Financial Officer of OPTI 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 Frame work) 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, 2009 based on the COSO Framework. Based on this evaluation, these officers concluded that as of December 31, 2009, 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. There has not been any change in OPTI’s internal control over financial reporting during the first quarter of 2010 that has materially affected, or is reasonably likely to materially affect OPTI’s internal control over fin ancial reporting.
CRITICAL ACCOUNTING ESTIMATES
Our critical accounting estimates are consistent with those noted in our 2009 annual MD&A dated February 8, 2010.
NEW ACCOUNTING PRONOUNCEMENTS
IFRS
The Canadian Accounting Standards Board announced that Canadian 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 International Financial Reporting Standards (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.
OPTI’s IFRS implementation project consists of three primary phases which will be completed by a combination of in-house resources and external consultants.
| ● | Initial diagnostic phase – Involves preparing a Preliminary Impact Assessment to identify key areas that may be impacted by the transition to IFRS. Each potential impact identified during this phase is ranked as having a high, moderate or low impact on our financial reporting and the overall difficulty of the conversion effort. |
| ● | Impact analysis, evaluation and solution development phase – Involves the selection of IFRS accounting policies by senior management and the review by the audit committee, the quantification of the impact of changes on our existing accounting policies on our opening IFRS balance sheet and the development of draft IFRS financial statements. |
| ● | Implementation and review phase – Involves training key finance and other personnel and implementation of the required changes to our information systems and business policies and procedures. It will enable us to collect the financial information necessary to prepare IFRS financial statements and obtain audit committee approval of IFRS financial statements. |
OPTI has completed the initial diagnostic phase and the impact analysis, evaluation and solution development phase is well advanced at quarter-end.
Business Impact of IFRS
Based on existing IFRS, the areas that have the potential for the most significant financial impact to us are the methodology for impairment testing, the absence of a comparable standard to full-cost accounting, treatment of transaction costs attributable to the issuance of our long-term debt and the accounting for decommissioning obligations. We are also assessing the exemptions to full restatement available under IFRS.
IFRS requires us to conduct an asset impairment test at the date of adoption of IFRS on January 1, 2011 if indicators of impairment exist. The test for impairment under IFRS requires the use of a discounted cash flow model to determine fair value, whereas Canadian GAAP uses an undiscounted cash-flow model and then discounted cash-flow model to evaluate impairment. Market factors such as discount rates and the price of oil will affect our evaluation of impairment. Accordingly, depending on these factors on the date of adoption, we may have an asset impairment loss. However, IFRS permits subsequent recovery of such write downs in future periods to the extent that fair value increases.
The absence of a full-cost standard equivalent in IFRS may lead to certain capitalized exploration and development costs under Canadian GAAP being recorded to opening retained deficit. In relation to oil and gas assets, IFRS only provides guidance up to the point that technical feasibility and commercial viability of extracting the resource is demonstrated, the exploration and evaluation phase. IFRS is in line with Canadian GAAP for the accounting for this phase but expenditures beyond this phase must be considered with the capitalization criteria for Property, Plant and Equipment (PP&E) and/or Intangible assets. OPTI’s initial assessment indicates that our development expenditures meet the rec ognition criteria in relation to PP&E, and no material impact on the measurement of PP&E is expected. The IASB has issued an IFRS 1 exemption for entities using the full cost method from retrospective application of IFRS for oil and gas assets. In addition IFRS requires that significant parts of an asset are recognized and depreciated separately where as Canadian GAAP has not specifically required this. Our current policy of depreciation is in line with the IFRS requirements and therefore no impact is anticipated for this.
Canadian GAAP includes specific standards that prescribe the method for the calculation of depletion which does not exist under IFRS. Canadian GAAP, under full-cost accounting, oil and gas assets are depleted using the unit-of-production method using remaining proved reserves. We are evaluating our accounting policy for depletion to possibly include proved and probable reserves, to determine if this more accurately reflects the usage of our resource assets.
Under Canadian GAAP, transaction costs that are directly attributable to long-term debt can be either netted off the associated debt and amortized into income using the effective interest method or expensed as incurred. We have chosen a policy under Canadian GAAP to expense these costs as incurred. Under IFRS, these costs must be netted off the associated debt and amortized into income using the effective interest method. This is expected to result in a decrease to our opening deficit and a decrease to our long-term debt.
Canadian GAAP includes specific guidance with respect to asset retirement obligations whereas under International Accounting Standards (IAS) asset retirement obligations are included under IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”. The threshold for recognition of a provision under IFRS is lower than under Canadian GAAP As a result a decommissioning liability for the Upgrader must be determined and recorded. Currently under Canadian GAAP, no liability has been recorded for the Upgrader as the present value cannot be reasonably determined as the asset has an indeterminable useful life. In addition, IFRS requires the use of the current market-based discount rate to be ap plied to the liability at each reporting date rather than the historical rate used when the liability was initially set-up. We do not expect that either of these impacts will be material.
IFRS 1 provides the framework for the first-time adoption of IFRS and specifies that an entity shall apply the principles under IFRS retrospectively. Certain optional exemptions and mandatory exceptions to retrospective application are provided under IFRS. We are completing our analysis of IFRS 1 with respect to the elective exemptions available.
NON-GAAP FINANCIAL MEASURES
The term net field operating margin (loss) 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 have presented this measure on a consistent basis from period to period and plan to do so in the future. We consider net field operating margin (loss) 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 earnings (loss) before taxes. For the periods noted, the following is a reconciliation of loss before taxes to ne t field operating loss.
$ millions | | Three months ended March 31, 2010 | | | Year ended 2009 | | | Year ended 2008 | |
| Loss before taxes | | $ | (50 | ) | | $ | (234 | ) | | $ | (593 | ) |
| Interest, net | | | 49 | | | | 150 | | | | 33 | |
| General and administrative | | | 4 | | | | 17 | | | | 18 | |
| Financing charges | | | — | | | | 22 | | | | 1 | |
| Impairment related to asset sale | | | — | | | | — | | | | 369 | |
| Loss on disposal of assets | | | — | | | | 1 | | | | — | |
| Foreign exchange loss (gain) | | | (72 | ) | | | (294 | ) | | | 373 | |
| Net realized loss (gain) on hedging instruments | | | 4 | | | | (40 | ) | | | (116 | ) |
| Net unrealized loss (gain) on hedging instruments | | | 26 | | | | 234 | | | | (160 | ) |
| Depletion, depreciation and accretion | | | 10 | | | | 26 | | | | 17 | |
| Net field operating loss | | $ | (29 | ) | | $ | (118 | ) | | $ | (58 | ) |
Our net field operating loss for the first quarter of 2010 and for the year ended December 31, 2009 represents our 35 percent working interest in the Project whereas net field operating loss for the year ended December 31, 2008 represents our then 50 percent working interest.
FINANCIAL INSTRUMENTS
The Company considers its risks in relation to financial instruments in the following categories:
Credit Risk
Credit risk is the risk that a 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.
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 March 31, 2010, 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. Our liquidity risk is increased by our relatively high levels of long term debt and historical net field operating losses. We mitigate liquidity risk by maintaining a sufficient cash balance, maintaining sufficient current and projected liquidity to meet expected future payments based upo n reasonable production and pricing assumptions and ensuring we have adequate sources of financing available through bank credit facilities and complying with debt covenants. Our financial liabilities arose primarily from the development of the Project. As at March 31, 2010, 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 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 March 31, 2010, we had mitigation programs to reduce market risk related to foreign exchange and commodity price changes. The primary market risks related t o our commodity contracts relate to future estimated prices for WTI.
For the first quarter of 2010 we have estimated the following changes to reported net income as a result of changes in market rates as noted. An increase of $1.00/bbl in WTI would have resulted in approximately $0.3 million decrease in our net loss with an offsetting increase in our net loss of approximately $0.6 million as a result of the increase in the value of our commodity liabilities (assuming the WTI change occurred in a range where the WTI price per barrel is greater than the strike price of our commodity swap), a $0.10/GJ increase in the price of natural gas would have resulted in approximately a $0.2 million increase in our net loss, a 1.0 percent increase in interest rates would have resulted in approximately a nil increase in our net loss and a $0.01 increase in the Canadian to U.S. exchange rate would decrease our net loss by approximately $10 million considering the impact on our Senior Notes and related interest and our foreign exchange forwards.
The following sections describe these risks in relation to the Company’s key financial instruments.
* Cash and Cash Equivalents
The Company has cash deposits and money market investments with Canadian banks. 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 March 31, 2010 the amount in cash and cash equivalents was $272 million and the maximum exposure to a single counterparty was $59 million with a major Canadian bank.
As at March 31, 2010, the remaining terms on investments made by the Company are less than 35 days with interest fixed over the period of investment. Maturity dates for investments are established to ensure cash availability for working capital requirements, operating activities and interest payments. Investments are held to maturity and the maturity value does not deviate with changes in market interest rates.
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 and Deposits
As at March 31, 2010, accounts receivable and deposits were $27 million. Our accounts receivable include amounts due from Nexen related to operating activities and Nexen Marketing related to marketing activities. As at March 31, 2010, our accounts receivable due from Nexen includes $12 million related to marketing activities. We have deposits of $12 million for operating expenses related to advances on joint venture expenses required under our joint venture agreement with Nexen. 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 in stitutions with an investment grade rating. Therefore, we estimate our risk of credit loss as low. Prepaid insurance and property tax costs of $3 million are amortized into earnings over the period of prepayment.
* Accounts Payable and Accrued Liabilities
As at March 31, 2010, accounts payable and accrued liabilities were $125 million. Accounts payable and accrued liabilities are comprised primarily of $65 million due in respect of development and operation of the Project, $56 million due in respect of interest on our Senior Notes and $4 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 Senior 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 March 31, 2010, long-term debt was $2,198 million 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 March 31, 2010. 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 $190 million 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. The extent of the exposure to interest rate risk depends on the amount outstanding under the facility. As at March 31, 2010, there were no amounts drawn under the revolving credit facility.
Our Senior Notes are comprised of US$2,175 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 Senior Notes. A CDN$0.01 change in the exchange rate will impact the carrying value of the Senior Notes by approximately $22 million. A CDN$0.01 change in the exchange rate will change our annual interest costs by approximately $2 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 & #8221;Liquidity and Capital Resources.”
* 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 March 31, 2010. These instruments are designated as held-for-trading and are measured at fair value at each financial statement date.
Foreign exchange hedging instruments
OPTI is exposed to foreign exchange rate risk on our long-term U.S. dollar-denominated debt. As at April 16, 2010, we had US$620 million of foreign currency forwards to manage a portion of the exposure to the foreign exchange variations on the Company’s long-term debt at a rate of approximately CDN$1.19 to US$1.00. Changes in the exchange rate between Canadian and U.S. dollars change the value of these instruments. These forward contracts currently expire in December 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$1.19 to US$1.00 on a portion of our debt. The foreign currency forwards at March 31, 2010 are a liability of $143 million which corresponds to a US$875 million notional amount outstanding as of the same date. By April 16, 2010 we settled a US$255 million notional amount of these foreign currency forwards with a payment of $44 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 at April 16, 2010, is less than 40 percent of the value of the forwards.
Prior to the expiry of the foreign exchange forward in December 2010, OPTI may choose to settle or to extend to a later settlement date. In the event that any 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 these forwards, we expect to pay or receive, based on the mark-to-market of this contract, at the time of the settlement. Based on the active market for the underlying market variables used in the valuation, we do not believe other market assumptions could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal evaluation. As of April 16, 2010, the value of the foreign currency forwards would change by approximately $6 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 2010.
Commodity hedging instruments
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 commodity price swaps to mitigate a portion of the exposure. As at March 31, 2010 the Company has commodity price swaps that provide for 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl of crude oil through to December 31, 2010. The value of these financial instruments as at March 31, 2010 was a liability of $17 million. The counterparties to the commodity hedges are major Canadian and international banks. Our exposure to non-pa yment from any single institution is approximately 33 percent of the value of the commodity asset with a major Canadian bank.
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 remaining commodity hedges would change b y approximately $0.8 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 2009 annual MD&A dated February 8, 2010.
