Exhibit 99.2
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended
December 31, 2009
1
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis (MD&A), dated February 8, 2010, should be read in conjunction with the audited financial statements for the year ended December 31, 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 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); OPTI's financial outlook, including 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.
2
Reserve and Resource Estimates: The estimates of bitumen resources and bitumen, PSCTM and butane reserves contained herein are forward-looking statements. The estimates are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by government agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. The estimates contained herein with respect to reserves and resources that may be developed and produced in the future have been based upon volumetric calculations and upon analogy to similar types of reserves and resources, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves and resources based upon production history will result in variations, which may be material, in the estimated reserves and resources.
Additional information relating to our Company, including our AIF, can be found at www.sedar.com.
FINANCIAL HIGHLIGHTS
| Years ended December 31 | ||||||||||||
In millions | 2009 | 2008 | 2007 | |||||||||
| Net earnings (loss) | $ | (306 | ) | $ | (477 | ) (1) | $ | 151 | ||||
| Working capital (deficiency) | 168 | (25 | ) | 271 | ||||||||
Total oil sands expenditures (2) | 148 | 706 | 961 | |||||||||
| Shareholders’ equity | $ | 1,311 | $ | 1,471 | $ | 1,951 | ||||||
Common shares outstanding (basic) (3) | 282 | 196 | 195.4 | |||||||||
Notes:
| (1) | Includes $369 million pre-tax asset impairment provision related to working interest sale to Nexen. |
| (2) | Capital expenditures related to Phase 1 and future phase development. Capitalized interest, hedging gains/losses and non-cash additions or charges are excluded. |
| (3) | Common shares outstanding at December 31, 2009 after giving effect to the exercise of stock options would be approximately 287 million common shares. |
OVERVIEW
OPTI is a Calgary, Alberta-based company with a 35% working interest in the Long Lake Project, which is operated by Nexen. The first phase of the Project consists of 72,000 bbl/day of SAGD (steam assisted gravity drainage) oil production integrated with an upgrading facility that uses OPTI's proprietary OrCrudeTM process and commercially available hydrocracking and gasification technologies. Through gasification, this configuration substantially reduces the exposure to and the need to purchase natural gas. The Project is expected to produce 58,500 bbl/d of products, primarily 39 degree API Premium Sweet Crude with low sulphur content, making it a highly desirable refinery feedstock. OPTI's common shares trade on the Toronto Stock Exchange under the symbol OPC.
3
PROJECT STATUS
Operations at the Long Lake Project in the fourth quarter of 2009 focused on ramping up the water treatment and steam generation facilities after the completion of a successful turnaround in the previous quarter. With improved water treatment, steam injection rose to an average of approximately 92,000 bbl/d for the months of November and December. Recent steam injection is approximately 105,000 bbl/d. The Project has been generating steam on a consistent basis since late October. We currently have 75 wells receiving steam with 57 wells producing.
With the reservoir in the early stages of warm-up post-turnaround, average bitumen production for the fourth quarter was approximately 13,600 bbl/d with an average of 15,800 bbl/d (5,530 bbl/d net to OPTI) for the months of November and December. Recent bitumen production is approximately 18,000 bbl/d (6,300 bbl/d net to OPTI).
The all-in steam to oil (SOR) is currently approximately 6.0 including steam to wells that are in the steam circulation stage and not yet producing bitumen. The SOR ratio of the producing wells was approximately 5.0 in November and December. This SOR is expected to be higher at the current stage of bitumen ramp-up than our long term estimate of 3.0. A number of our wells have recently been converted to production status from circulation status which would be expected to result in an initially higher SOR. We expect SOR to decline during 2010 assuming we are able to maintain our recent reliability in delivering steam to wells.
Upgrader on-stream time has increased significantly, averaging 79% in November and December after a late October start up. Improved reliability allowed the Project to process over 90% of produced and purchased bitumen after the Upgrader start up in the fourth quarter. During the SAGD ramp-up period, we expect to purchase approximately 10,000 bbl/d of externally sourced bitumen.
The solvent deasphalter and thermal cracking units are now in operation, allowing the Upgrader to transition from gasifying vacuum residue to gasifying asphaltenes. As a result, PSCTM yields have increased to approximately 70%. Yields are expected to increase to the design rate of 80% as the Project reaches higher bitumen volumes.
FUTURE PHASES
In 2010, OPTI will invest approximately $23 million in advancing Phase 2 engineering and detailed execution plans, with $5 million budgeted for development of Phases 3 through 6. OPTI and its joint venture partner, Nexen, have agreed to defer the sanctioning of Phase 2 to late 2011 in order to gain additional Phase 1 operating experience prior to construction of future phases, as well as to obtain greater clarity on carbon dioxide regulations.
STRATEGIC ALTERNATIVES REVIEW
In November 2009, OPTI announced that its Board of Directors has initiated a process to explore strategic alternatives for enhancing shareholder value. The improving economic environment, recent operational improvements, strengthening merger and acquisition valuations for oil sands assets and the future potential of OPTI's assets support OPTI's 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
4
ultimate objective of carrying out this review is to determine which alternative(s) might result in superior value for shareholders.
ENHANCED LIQUIDITY
On November 20, 2009, we announced the completion of the issuance of US$425 million face value of 9.0% Notes (US$425 million First Lien Notes) due December 15, 2012 at a price of 97.0%, resulting in a yield to maturity of approximately 10.2%. The purpose of the offering was to establish sufficient liquidity through the ramp-up period of the Long Lake Project and flexibility for the Company to proceed with its review of strategic alternatives.
RESERVES AND RESOURCES
OPTI has a significant presence in the Athabasca oil sands, with a 35 percent interest in over 406 sections of land primarily on three leases: Long Lake (which includes Long Lake Phase 1 and Kinosis), Leismer and Cottonwood. We believe our existing lands will support approximately 360,000 bbl/d of PSCTM production (126,000 bbl/d net to OPTI) from six phases including Long Lake Phase 1. Based on reserve and resource estimates, we believe there is potential for three phases at Long Lake, two phases at Leismer and one at Cottonwood. With a limited delineation program in the 2008/2009 winter drilling season, estimates of total reserve and resource volumes for 2009 did not change significantly from 2008.
Reserves
McDaniel & Associates (McDaniel), our independent reserves and resources evaluator, has prepared a report evaluating the bitumen reserves and synthetic oil reserves of the Long Lake leases effective December 31, 2009.
McDaniel categorizes their estimates as proved, probable and possible reserves over various parts of the Long Lake Leases. Proved, probable and possible reserves are booked over the Phase 1 area (noted as “Long Lake”), and probable and possible reserves are booked over the Phase 2 and 3 areas (noted as “Kinosis”).
The recognition of reserves in the Kinosis area is largely due to the level of delineation of the leases, the regulatory approval for up to 140,000 bbl/d of bitumen production from Kinosis and the advanced stage of the Phase 2 development. The evaluation of the reserves in the Kinosis area includes only the 72,000 bbl/d Phase 2 development, as Phase 3 will occur subsequent to Phase 2. It is expected that upon Phase 2 receiving formal sanctioning by OPTI and our partner, some of the probable reserves would be categorized as proved; it is also expected that as Phase 3 advances and becomes more certain, that the full 140,000 bbl/d development will be considered in the estimation of reserves.
The McDaniel evaluation of our reserves recognizes the impact of upgrading on the resources. Most of the raw bitumen will be upgraded and sold as PSC™ and butane, and is shown as synthetic crude oil or butane reserves. Bitumen was sold prior to Upgrader start-up, is planned to be sold during periods of Upgrader downtime, and is shown as bitumen reserves.
5
The following table shows OPTI’s 35 percent working interest, before royalties, in the raw bitumen reserves and the corresponding sales volumes at December 31, 2009.
Summary of Reserve Volumes
As at December 31, 2009
(volumes in millions of barrels)
| Raw Bitumen | Sales Volumes | |||||||||||||||
| PSC™ | Bitumen | Butane | ||||||||||||||
Proven (1) | 194 | 149 | 8 | 3 | ||||||||||||
Proven plus probable (2) | 711 | 553 | 34 | 8 | ||||||||||||
Proven plus probable plus possible (3) | 780 | 608 | 35 | 9 | ||||||||||||
| Notes to reserve table: |
| (1) Proven reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proven reserves. |
| (2) Probable reserves are those additional reserves that are less certain to be recovered than proven reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proven plus probable reserves. |
| (3) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the remaining quantities actually recovered will be greater than the sum of proven plus probable plus possible reserves. |
Resources
In addition to the proved, probable and possible reserves, there are contingent resources associated with the Long Lake leases. The reserve estimates limit the life of the project to 50 years, so any recoverable volume that remains beyond this time is categorized as a contingent resource. In addition, some areas of the lease with a lower density of delineation has volumes that are categorized as contingent resources.
There are bitumen resources estimated for both the Leismer and Cottonwood leases, some of which are categorized as contingent resources and some are categorized as prospective resources. A summary of the resource estimates as at December 31, 2009, on a 35 percent working interest, before royalties, is shown below:
Summary of Resource Volumes
As at December 31, 2009
(volumes in millions of barrels)
Raw Bitumen (1) | ||
Contingent Resources (2) | Prospective Resources (3) | |
Long Lake (4) | 153 | - |
Kinosis (4) | 167 | - |
Leismer (4) | 591 | - |
Cottonwood (5) | 203 | 314 |
| Total | 1,114 | 314 |
6
notes to resource table:
| (1) | These estimates represent the "best estimate" of our resources, are not classified or recognized as reserves, and are in addition to our disclosed reserve volumes. |
| (2) | Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources. |
| (3) | Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. |
| (4) | The resource estimates for Long Lake, Kinosis and Leismer are categorized as Contingent Resources. These volumes are classified as resources rather than reserves primarily due to less delineation and the absence of regulatory approvals, detailed design estimates and near-term development plans. |
| (5) | The resource estimate for Cottonwood is categorized as both Contingent and Prospective Resources. These Contingent Resource volumes are classified as resources rather than reserves primarily due to less delineation; the absence of regulatory approvals, detailed design estimates and near-term development plans; and less certainty of the economic viability of their recovery. In addition to those factors that result in Contingent Resources being classified as such, Prospective Resources are classified as such due to the absence of proximate delineation drilling. |
NETBACKS
We have provided below an update to our estimated netback for Phase 1 of the Project that was last updated in our third quarter MD&A filed on SEDAR on October 27, 2009. The netback calculation at each West Texas Intermediate (WTI) price has been updated for a lower natural gas prices, a stronger Canadian dollar relative to the U.S. dollar, a lower heavy/light crude oil price differential and lower electricity sale prices. Management approved this netback calculation on February 1, 2010.
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.
7
Estimated Future Project Pre-Payout Netbacks(1)
WTI - US$60(2) | WTI - US$75(3) | WTI - US$90(4) | ||||||||||
| $/bbl | $/bbl | $/bbl | ||||||||||
Revenue(1) | $ | 69.43 | $ | 82.27 | $ | 93.75 | ||||||
| Royalties and Corporate G&A | (2.86 | ) | (4.10 | ) | (5.65 | ) | ||||||
Operating costs(5) | ||||||||||||
Natural gas(6) | (2.67 | ) | (3.15 | ) | (3.58 | ) | ||||||
Other variable(7) | (2.00 | ) | (2.00 | ) | (2.00 | ) | ||||||
| Fixed | (15.46 | ) | (15.46 | ) | (15.46 | ) | ||||||
Property taxes and insurance(8) | (2.81 | ) | (2.81 | ) | (2.81 | ) | ||||||
| Total operating costs | (22.94 | ) | (23.42 | ) | (23.85 | ) | ||||||
Netback(9) | $ | 43.63 | $ | 54.75 | $ | 64.25 | ||||||
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$5.00/mcf, foreign exchange rates of $1.00 = US$0.85, heavy/light crude oil price differentials of 30 percent of WTI and electricity sales prices of $70.40 per MegaWatt hour (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$6.25/mcf, foreign exchange rates of $1.00 = US$0.90, heavy/light crude oil price differentials of 27 percent of WTI and electricity sales prices of $83.12 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$7.50/mcf, foreign exchange rates of $1.00 = US$0.95, heavy/light crude oil price differentials of 24 percent of WTI and electricity sales prices of $94.49 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 and 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.
8
Based on US$60WTI and the other assumptions set out in the notes above, we expect our operating costs at full production plus royalties and corporate G&A expenses to be $25.79 per barrel of products sold. Using a foreign exchange rate of CDN$1.00 = US$0.85, the annual interest on our Senior Notes is approximately $30.00 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 Notes (as defined below) at approximately $56.00 per barrel (US$48.00 per barrel) of products sold.
RESULTS OF OPERATIONS
| Years ended December 31 | ||||||||||||
$ millions, except per share amounts | 2009 | 2008 | 2007 | |||||||||
| Revenue, net of royalties | $ | 143 | $ | 198 | $ | - | ||||||
| Expenses | ||||||||||||
| Operating expense | 146 | 84 | - | |||||||||
| Diluent and feedstock purchases | 102 | 164 | - | |||||||||
| Transportation | 13 | 8 | - | |||||||||
| Net field operating margin (loss) | (118 | ) | (58 | ) | - | |||||||
| Corporate expenses | ||||||||||||
| Interest, net | 150 | 33 | (13 | ) | ||||||||
| General and administrative | 17 | 18 | 14 | |||||||||
| Financing charges | 22 | 1 | 12 | |||||||||
| Realized gain on hedging instruments | (40 | ) | (116 | ) | - | |||||||
| Earnings (loss) before non-cash items | (267 | ) | 6 | (13 | ) | |||||||
| Non-cash items | ||||||||||||
| Foreign exchange translation loss (gain) | (294 | ) | 373 | (235 | ) | |||||||
| Net unrealized loss (gain) on hedging instruments | 234 | (160 | ) | 61 | ||||||||
| Depletion, depreciation and accretion | 26 | 17 | 2 | |||||||||
| Impairment related to asset sale | - | 369 | - | |||||||||
| Loss on disposal of assets | 1 | - | - | |||||||||
| Future tax expense (recovery) | 72 | (116 | ) | 8 | ||||||||
| Net earnings (loss) | $ | (306 | ) | $ | (477 | ) | $ | 151 | ||||
| Earnings (loss) per share, basic and diluted | $ | (1.28 | ) | $ | (2.43 | ) | $ | 0.77 | ||||
Operational Overview
The results of operations for the year ended December 31, 2009 include SAGD results for the entire year, as well as Upgrader results from April 1, 2009, the date we determined the Upgrader to be ready for its intended use for accounting purposes. The results for the year ended December 31, 2008 include SAGD results from July 1, 2008, the date we determined the SAGD facility to be ready for its intended use.
9
Results related to the Long Lake Project from 2008 are at a working interest share of 50%, whereas 2009 results are at a 35% working interest share due to the sale of 15% of our working interest to Nexen, effective January 1, 2009. This means that analysis of all financial results associated with joint venture activities should consider that the lower working interest will reduce the amount reported by OPTI related to these activities in 2009 as compared with 2008.
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 $118 million for the year ended December 31, 2009 as compared with a loss of $58 million in the preceding year. The net field operating loss was affected by 2009 results including a full year of SAGD operations and nine months of Upgrader operations whereas 2008 includes only SAGD results from July 1, 2008 onward. The increase is partially offset by the decrease in working interest from 50% in 2008 to 35% in 2009. We had a net field operating loss in both years due to relatively low bitumen production in addition to a relatively low on-stream factor for the Upgrader in 2009. Revenue in 2008 was a combination of Premium Synthetic Heavy (PSH) and power sales. Revenue in 2009 was a combination of PSCTM, PSH and power sales.
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. The Upgrader on-stream factor from April 1, 2009 to December 31, 2009 was 39% (2008 – nil). When the Upgrader is not in operation, results are adversely affected by the requirement to purchase diluent, which is blended with bitumen to produce 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 diluent costs.
During the fourth quarter of 2009, our net field operating loss improved from $38 million in the third quarter to $21 million. The on-stream factor increased from 15% to 56% which resulted in a significant increase in PSC™ sales. Our share of PSC™ sales in the fourth quarter increased to 3,000 bbl/day compared to 800 bbl/day in the third quarter while our share of PSH sales decreased to 3,300 bbl/day from 5,600 bbl/day in the third quarter. Our operating costs decreased to $35 million in the fourth quarter from $44 million in the third quarter. Third quarter costs included maintenance work as part of the turnaround in the third quarter. In addition, fourth quarter diluent and feedstock purchases also decreased due to the higher on stream factor.
Revenue
For the year ended December 31, 2009, we earned revenue net of royalties of $144 million, compared to $198 million in 2008. During 2009 our share of PSC™ sales averaged 1,800 bbl/day (2008: nil bbl/day) at an average price of approximately $73/bbl (2008: $nil/bbl), while our share of PSH averaged 5,300 bbl/day (2008: 15,450 bbl/day) at an average price of approximately $54/bbl (2008: $66/bbl). Bitumen production in 2009 averaged 4,400 bbl/day compared to 4,100 bbl/day in 2008. Our total revenue, net of royalties, diluent and feedstock increased to $41 million in 2009 compared to $34 million in 2008 due to higher PSC™ sales in 2009 and lower PSH sales from bitumen
10
blended with diluent. The revenue increase would be higher however it was offset by the change in OPTI’s working interest from 50% in 2008 to 35% in 2009.
During 2009 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 to increase the premium we receive relative to other synthetic crude oils as production, and therefore the availability of marketed PSCTM, increases.
For the year ended December 31, 2009, we had power sales of $5 million representing approximately 102,800 megawatt hours (MWh) of electricity sold at an average price of approximately $49/MWh compared to power sales of $11 million in 2008 which represented 141,800 MWh. The decrease in power sales was a result of lower excess electricity available due to a higher Upgrader on-stream factor and lower market prices for electricity. The decrease would be lower, however it was offset by the change in OPTI’s working interest from 50% in 2008 to 35% in 2009.
Expenses
* Operating expenses
For the year ended December 31, 2009 and 2008, operating expenses were primarily comprised of natural gas, maintenance, labour, operating materials and services.
For the year ended December 31, 2009, operating expenses were $146 million compared to $84 million in 2008. Operating expenses in 2009 are higher as they include SAGD results for the entire period, as well as Upgrader results from April 1, 2009, whereas operating expenses in 2008 only include SAGD results from July 1, 2008. There were no Upgrader operating expenses in 2008 since these costs were capitalized as the Upgrader was not considered to be ready for its intended use. In addition, in 2009 we performed maintenance work as part of a turnaround in September which increased operating expenses. The increase would be higher however it was offset by the change in OPTI’s working interest from 50% in 2008 to 35% in 2009.
* Diluent and feedstock purchases
For the year ended December 31, 2009, diluent and feedstock purchases were $102 million compared to $164 million in 2008. In 2009 we purchased approximately 2,400 bbl/day of diluent at an average price of $67/bbl, compared to 2008 purchases of 8,400 bbl/day at an average price of $96/bbl. The 2008 purchases are attributable to the last six months of 2008. Diluent purchases decreased in 2009 compared to 2008 due the Upgrader startup in 2009. The decrease was offset by diluent and feedstock purchases in 2009 that include purchases for the entire period, whereas diluent and feedstock purchases in 2008 only include purchases from July 1, 2008. A portion of the decrease was due to the change in OPTI’s working interest from 50% in 2008 to 35% in 2009.
In 2009 and 2008, we purchased approximately 2,000 bbl/day of third party bitumen. The 2008 purchases are attributable to the last six months of 2008, as feedstock purchases prior to July 1, 2008 were capitalized.
11
* Transportation
For the year ended December 31, 2009, transportation expenses were $13 million compared to $8 million in 2008. Transportation expenses were primarily related to pipeline costs associated with PSCTM and PSH sales. The increase in transportation expenses in 2009 was a result of expenses for the entire period, whereas transportation expenses in 2008 are only included from July 1, 2008. The increase would be higher however it was offset by the change in OPTI’s working interest from 50% in 2008 to 35% in 2009.
Corporate expenses
* Net interest expense
For the year ended December 31, 2009, net interest expense was $150 million compared to $33 million in 2008. Net interest expense increased primarily due to interest costs in 2009 including interest related to the SAGD facilities for the entire period as well as interest costs related to the Upgrader from April 1, 2009, whereas interest expenses in 2008 only included interest related to the SAGD facilities from July 1, 2008. The increase was offset by lower average amounts owing on the revolving credit facility and lower Canadian interest costs on our U.S. dollar-denominated debt due to stronger Canadian dollar in 2009 compared to 2008.
* General and Administrative (G&A)
For the year ended December 31, 2009, G&A expense was $17 million, compared to $18 million in 2008. G&A expenses were lower in 2009 due to our reduced head office costs since we are no longer the operator of the Upgrader. This was offset by one-time transition costs in the second quarter related to the re-organization of OPTI after the asset sale to Nexen. Included in G&A expense is stock-based compensation expense of $1 million (2008: $2 million).
* Financing charges
For the year ended December 31, 2009, financing charges were $22 million compared to $1 million in 2008. Financing charges in 2009 are due to the amendments to our revolving credit facility and issuance of the US$425 million First Lien Notes, while financing charges in 2008 related to the establishment of a $150 million revolving credit facility.
* Net realized gain on commodity hedging instruments
For the year ended December 31, 2009, net realized gain on hedging instruments was $40 million compared to a gain of $116 million in 2008. The gains in 2009 are related to our US$80/bbl crude oil puts and our US$77/bbl crude oil swaps. The gain in 2008 was related to gains on foreign exchange hedges.
Non-cash items
* Foreign exchange gain or loss
For the year ended December 31, 2009, foreign exchange translation was a $294 million gain compared to a $373 million loss in 2008. The gain or loss is comprised of the re-measurement of our U.S. dollar-denominated long-term debt and cash. During 2009 the Canadian dollar strengthened from CDN$1.22:US$1.00 to CDN$1.05:US$1.00,
12
resulting in a foreign exchange translation gain in the year. In 2008, the Canadian dollar weakened from CDN$0.99:US$1.00 to CDN$1.22:US$1.00, resulting in a foreign exchange loss. These gains and losses are unrealized.
* Net unrealized gain or loss on hedging instruments
For the year ended December 31, 2009, net unrealized loss on hedging instruments was $234 million, compared to a $160 million gain in 2008. The net unrealized loss in 2009 is comprised of a $146 million unrealized loss on our foreign exchange hedges due to the strengthening of the Canadian dollar from CDN$1.22:US$1.00 to CDN$1.05:US$1.00 and a $88 million unrealized loss on our commodity hedges as the future price of WTI increased from approximately US$41/bbl at the beginning of the year to approximately US$79/bbl at year-end. The gain in 2008 was due to a $93 million increase in the fair value of our foreign exchange hedges due to a weakening Canadian dollar and a $67 million increase in the fair value of our commodity hedges as the future price for WTI decreased in 2008.
* Depletion, depreciation and amortization
For the year ended December 31, 2009, depletion, depreciation and amortization (DD&A) was $26 million, compared to $17 million in 2008. The DD&A in 2009 is based on a full year of SAGD operations and nine months of the Upgrader from April 1, 2009. In 2008, DD&A only related to the depletion and depreciation of the SAGD facilities starting July 1, 2008.
* Impairment Related to Asset Sale
On January 27, 2009, OPTI announced that we had completed the sale of a 15 percent working interest in our joint venture assets to our partner Nexen for $735 million. Effective January 1, 2009, OPTI has a 35 percent working interest in all joint venture assets, including Phase 1 of the Project, all future phase reserves and resources, and future phases of development.
To evaluate impairment as of December 31, 2008, assets were grouped into categories of depreciable assets, resource assets and unproved properties based on the nature of the asset. Each asset type was assessed individually for impairment.
We allocated the sales proceeds to each asset type based on an estimate of fair value. The sales proceeds of $721 million, net of transaction costs, allocated to depreciable assets were lower than the book value of the asset; as a result, impairment before taxes of $369 million was recorded in 2008. The sales proceeds allocated to resource assets did not alter the depletion rate by greater than 20 percent and, as a result, no gain or loss was recorded. The sales proceeds for resource assets were recorded as a reduction to book value in 2009. The sales proceeds for unproved properties were recorded as a reduction to book value as of completion of the sale in 2009. All of the Company’s remaining assets were subject to a ceiling test and cost recovery test which concluded no further impairment existed. The ceiling test and cost recovery is described in Note 2 of the financial statements.
13
* Loss on disposal of assets
For the year ended December 31, 2009, loss on disposal of assets was $1 million compared to $nil million in 2008. The loss on disposal of assets in 2009 was primarily for costs incurred during the first quarter related to the asset sale to Nexen and information technology write-offs in the second quarter. There were no asset disposals in the corresponding period in 2008.
* Future tax expense (recovery)
For the year ended December 31, 2009, future tax expense was $72 million, compared to $116 million recovery in 2008. In 2008, the future tax recovery was the result of recognizing the future tax benefit derived from losses before tax offset by the impact of future tax rate changes. For 2009, 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 of $149 million against our future tax assets. We will assess the need for this valuation allowance at 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 | 2009 | 2008 | 2007 | |||||||||
| Long Lake Project – Phase 1 | ||||||||||||
| Upgrader & SAGD | $ | 20 | $ | 480 | $ | 811 | ||||||
| Sustaining capital | 63 | 60 | 17 | |||||||||
| Capitalized operations | 19 | 32 | 37 | |||||||||
| Total Long Lake Project | 102 | 572 | 865 | |||||||||
| Expenditures on future phases | ||||||||||||
| Engineering and equipment | 21 | 64 | 35 | |||||||||
| Resource acquisition and delineation | 25 | 70 | 61 | |||||||||
| Total oil sands expenditures | 148 | 706 | 961 | |||||||||
| Capitalized interest | 29 | 139 | 130 | |||||||||
| Other capital expenditures | (19 | ) | 45 | 17 | ||||||||
| Total cash expenditures | 158 | 890 | 1,108 | |||||||||
| Non-cash capital charges | - | 11 | 1 | |||||||||
| Total capital expenditures | $ | 158 | $ | 901 | $ | 1,109 | ||||||
For the year ended December 31, 2009 we incurred capital expenditures of $158 million. Phase 1 expenditures for Upgrader and SAGD of $20 million were primarily related to the construction and commissioning of the steam expansion project, which is substantially complete at year-end.
As with all SAGD projects, new well pads must be drilled and tied into the SAGD central facility in order to maintain production at design rates over the life of the Project. In 2009, we had sustaining capital expenditures of $63 million
14
related primarily to the optimization of the SAGD and Upgrader plants, resource delineation for future Phase 1 well pads, as well as completion of an additional SAGD well pad (first steam to these wells occurred during the fourth quarter of 2009).
Capitalized operations of $19 million relate to our share of Upgrader operations until April 1, 2009, the date we discontinued capitalizing Upgrader operations as the Upgrader was ready for its intended use. These costs consist of labour, maintenance and other operating expenses for the first three start-up months of the Upgrader.
For the year ended December 31, 2009, we incurred expenditures of $21 million for engineering and $25 million for resource delineation for future phases. Engineering progress will allow us to be in a position to sanction phase 2 of the Long Lake project in late 2011. Resource delineation for future phases is for lease acquisitions and other delineation activities.
Capitalized interest for the year ended December 31, 2009 includes interest costs of $29 million until April 1, 2009 on the estimated portion of long term debt attributable to the Upgrader. The reduction in other capital expenditures of $19 million relate to a reduction on the balance of Upgrader inventories and the write-off of previously capitalized transaction costs in connection with the working interest sale to Nexen.
Non-cash capital charges were nil for the year ended December 31, 2009 compared to $11 million in 2008. Effective January 1, 2009 we retroactively adopted CICA Handbook section 3064 “Goodwill and Intangible Assets”, which resulted in previously capitalized gains and losses related to the translation of our U.S. dollar debt as well as unrealized gains and losses related to certain financial derivatives associated with our debt to no longer meet the criteria for capitalization in 2009.
SELECTED ANNUAL INFORMATION
In millions (except per share amounts) | 2009 | 2008 | 2007 | |||||||||
| Total revenue | $ | 144 | $ | 198 | $ | - | ||||||
| Net (loss) earnings | (306 | ) | (477 | ) | 151 | |||||||
| Net (loss) earnings per share, basic and diluted | (1.28 | ) | (2.43 | ) | 0.77 | |||||||
| Total assets | 3,824 | 4,472 | 4,002 | |||||||||
| Total long-term liabilities | 2,300 | 2,656 | 1,861 | |||||||||
In 2008, revenue was mainly attributable to the sale of PSH after July 1, 2008, the date we determined the SAGD facility to be ready for its intended use. In 2009, revenue was comprised of sales of PSH for the entire year as well as sales of PSCTM after April 1, 2009, the date we determined the Upgrader to be ready for its intended use. A portion of the decrease was due to the change in OPTI’s working interest from 50% in 2008 to 35% in 2009.
Earnings (loss) 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
15
on hedging instruments, and fluctuating future tax expense. During 2007, we had a foreign exchange translation gain of $235 million and a $61 million unrealized loss on hedging instruments. During 2008, we recorded a before tax impairment of assets as a result of our working interest sale of $369 million and a total future tax recovery of $116 million. In addition, we had a $373 million foreign exchange translation loss, a $160 million unrealized gain on hedging instruments and a $116 million realized gain on hedging instruments. Also in 2008, we commenced recognition of revenue and operating expenses associated with early stages of SAGD operation. During 2009, we had a net field operating loss of $118 million, a $294 million foreign exchange translation gain, a $234 million unrealized loss on hedging instruments, a $40 million realized gain on hedging instruments and a future tax expense of $72 million.
Total assets increased in 2008 from 2007 as a result of expenditures on the Project and future phase development offset by the asset impairment at December 31, 2008. Our total assets have decreased in 2009 as a result of the proceeds from the asset sale in January 2009 offset by capital expenditures on the Project and future phase development. The increase in long-term financial liabilities from 2007 to 2008 was a result of weaker Canadian dollar increasing the measurement on our U.S. dollar denominated debt and borrowings under our revolving credit facility. Increases in long-term financial liabilities in 2009, are a result of the new US$425 million First Lien Notes issued November 20, 2009 offset by a stronger Canadian dollar decreasing the measurement amount of our U.S. dollar denominated debt and payments to reduce the balance of our revolving credit facility.
SUMMARY FINANCIAL INFORMATION
| 2009 | 2008 | |||||||||||||||||||||||||||||||
In millions (except per share amounts) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||||||||||
| Revenue | $ | 43 | $ | 38 | $ | 34 | $ | 29 | $ | 69 | $ | 126 | $ | - | $ | - | ||||||||||||||||
| Net earnings (loss) | (212 | ) | 12 | (9 | ) | (97 | ) | (410 | ) | (32 | ) | (29 | ) | (6 | ) | |||||||||||||||||
| Earnings (loss) per share, basic and diluted | $ | (0.75 | ) | $ | 0.04 | $ | (0.04 | ) | $ | (0.50 | ) | $ | (2.09 | ) | $ | (0.16 | ) | $ | (0.14 | ) | $ | (0.03 | ) | |||||||||
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 third quarter of 2008, we had a $64 million unrealized gain on hedging instruments. In the third and fourth quarters of 2008, we generated revenue and incurred operating expenditures associated with early stages of SAGD operation. During the fourth quarter of 2008, we had a pre-tax asset impairment for accounting purposes related to our working interest sale of $369 million and a future tax expense recovery of $116 million, primarily related to this
16
impairment, as well as a $254 million foreign exchange translation loss and $105 million realized gain and a $28 million unrealized gain on hedging instruments.
Operations during 2009 represent initial stages of operation at relatively low operating volumes and our operating results associated with these activities are expected to improve as SAGD production increases and the Upgrader produces higher volumes of PSCTM. Refer also to explanations in results of operations regarding realized and unrealized gains and losses related to foreign exchange translation and hedging instruments.
Net loss of $97 million in the first quarter of 2009 was associated with operating expenses in the early stages of SAGD operations that are operating at relatively low volumes which lead to a net field operating loss of $31 million. In addition, we had a $75 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 are primarily due to a $162 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 an operating loss of $21 million, interest expense of $43 million, financing charges of $17 million, an unrealized loss on our hedges of $36 million offset by a foreign exchange gain of $36 million, $12 million for G&A and depletion and depreciation and a future tax expense of $119 million that resulted from the recognition of a valuation allowance against our entire future tax asset.
During the third quarter of 2009, OPTI issued 85.7 million common shares increasing the total issued and outstanding shares from 196 million to 282 million. This reduces our earnings or loss per share by approximately 30% in the third and fourth quarter of 2009.
SHARE CAPITAL
At January 31, 2010, OPTI had 281,749,526 common shares and 5,512,216 common share options outstanding, of which 2.2 million common share options have an exercise price of less than $5.00 per share. The common share options have a weighted average exercise price of $6.90 per share. At January 31, 2010, OPTI’s fully diluted shares outstanding were 286,901,742.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2009, we had approximately $548 million of financial resources, consisting of $358 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 currently 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 cash outflows in 2010 include a capital budget of $119 million, primarily directed toward sustaining capital at the Long Lake project. Additionally, OPTI will incur interest payments of US$180 million this year. Our financial resources will also be affected by net field operating margin. Our net field operating margin was a loss of
17
$118 million in 2009. In order for the net field operating margin to become positive in 2010, some or all of the following will be required: a significant 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 operating costs. In part based on our expectation of a significant increase in bitumen production, we expect our financial resources are sufficient to meet our obligations through 2010.
OPTI intends to extend our foreign exchange forward contracts past their current short term maturity dates. If the contracts cannot be extended the cash settlement will be a function of the foreign exchange rate in effect at the maturity date. At the year end 2009 foreign exchange rate of CAD$1.00 to US$0.95, the cash settlement would have been $115 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 $9 million.
For the year ended December 31, 2009, cash used by operating activities was $226 million, cash used by financing activities was $74 million and cash provided by investing activities was $454 million. These changes, combined with a loss on our U.S. dollar denominated cash of $13 million, resulted in an increase in cash and cash equivalents during the period of $141 million.
During 2009, we used our existing cash, proceeds from our working interest sale to Nexen, net proceeds from our equity issuance and US$425 million First Lien Note issuance to repay our revolving credit facility, interest on our Senior Notes and to fund our capital expenditures and start-up activities. In 2010, existing cash and our undrawn revolving credit facility is expected to fund our expenditures.
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 fourth quarter and for the year ending 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, we may determine that we require additional capital to maintain adequate liquidity.
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
18
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.
The total debt to capitalization covenant in our revolving credit facility 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 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 the $85 million increase to the January 1, 2009 opening deficit as a result of new accounting pronouncements effective on that date. At December 31, 2009, this means for the purposes of this covenant calculation that our debt would be increased by the amount of our foreign exchange forward liability in the amount of $115 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.
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 a confirmation 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 may require additional financial resources to develop such phases.
19
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 could result in additional funding requirements earlier than we have estimated. Should the Company require such funding, it may be difficult to obtain such financing.
CREDIT RATINGS
OPTI maintains a company rating and a rating for its revolving credit facility and Senior Notes with Moody’s Investor Service (Moody’s) and Standard and 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 |
Moody’s assigned a B2 rating to the US$425 million notes and a B1 rating to the revolving Credit Facility. Moody’s lowered the ratings on the 8.25% and 7.875% notes from Caa1 to Caa3 and OPTI’s corporate rating from Caa1 to Caa2. The outlook remains negative according to Moody’s.
S&P assigned a B+ rating to the US$425 million notes and a B+ rating to the Revolving Credit Facility. The ratings on the 8.25% and 7.875% notes remain at B and OPTI’s corporate rating at B-. S&P removed ratings from Credit Watch with negative implications. The outlook remains negative according to S&P.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
During the year ended December 31, 2009, our long term debt decreased by $345 million due to the repayment of our revolving credit facility, as well as due to a lower Canadian dollar equivalent amount for our Senior Notes (principal and interest) due to a stronger Canadian dollar offset by the addition of US$425 million First Lien Notes.
20
The following table shows our contractual obligations and commitments related to financial liabilities at December 31, 2009.
| In $ millions | Total | 2010 | 2011 – 2012 | 2013 – 2014 | Thereafter | |||||||||||||||
Accounts payable and accrued liabilities(1) | $ | 68 | $ | 68 | $ | - | $ | - | $ | - | ||||||||||
Long-term debt (Senior Notes - principal)(2) | 2,286 | - | 447 | 1,839 | - | |||||||||||||||
Long-term debt (Senior Notes - interest)(3) | 719 | 192 | 378 | 149 | - | |||||||||||||||
Capital leases(5) | 68 | 3 | 6 | 6 | 53 | |||||||||||||||
Operating leases and other commitments(5) | 71 | 10 | 20 | 15 | 26 | |||||||||||||||
| Total commitments | $ | 3,212 | $ | 273 | $ | 851 | $ | 2,009 | $ | 79 | ||||||||||
Notes:
| (1) | Excludes accrued interest expense related to the Senior Notes. |
| (2) | Consists of principal repayments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.05 to US$1.00 at December 31, 2009. |
| (3) | Consists of scheduled interest payments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.05 to US$1.00 at December 31, 2009. |
| (4) | At December 31, 2009, 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. Such amounts are not material relative to our other commitments. |
| (5) | Consists of our share of future payments under our product transportation agreements with respect to future tolls during the initial contract term. |
OFF-BALANCE-SHEET ARRANGEMENTS
We have no off-balance-sheet arrangements.
CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S securities law. As of the year ended December 31, 2009, an evaluation was carried out under the supervision of and with the participation of OPTI’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of OPTI’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by OPTI in reports that it files with or submits under applicable securities legislation is recorded, processed, summarized and reported within the time periods required.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of OPTI Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the United States Securities and Exchange Commission and the Canadian Securities Administrators. The Company’s internal control over financial reporting is a process designed
21
under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with GAAP.
The Company’s internal control over financial reporting includes policies and procedures that:
| · | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of the Company; |
| · | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles; and |
| · | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. |
The Company’s internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures.
Management, including The Chief Executive Officer and Chief Financial Officer assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, based on the framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2009.
The Company has determined that a material change in internal controls over financial reporting 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.
CRITICAL ACCOUNTING ESTIMATES
Capital Assets
We capitalize costs in connection with the development of oil sands projects. The measurement of these costs at each financial statement date requires estimates to be made with respect to construction, materials procurement and drilling activities. An increase in the measurement amount of these items would increase our property, plant and equipment and accrued liabilities accordingly.
22
Capital assets are reviewed annually for impairment whenever events or conditions indicate that the net carrying amount may not be recoverable from estimated future cash flows. We have evaluated our assets and determined that these costs are recoverable based on our ceiling test and cost recovery as described in our accounting policies.
The quantity of reserves is subject to a number of estimates and projections, including assessment of engineering data, projected future rates of production, characteristics of bitumen reservoirs, commodity prices, foreign exchange rates, operating costs and sustaining capital expenditures. These estimates and projections are uncertain as we do not have a long commercial production history to assist in the development of these forward-looking estimates. However, all reserve and associated financial information is evaluated and reported on by a firm of qualified independent reserve evaluators in accordance with the standards prescribed by applicable securities regulators.
The calculation of future cash flows based on these reserves is dependent on a number of estimates including: production volumes, facility performance, commodity prices, royalties, operating costs, sustaining capital and foreign exchange rates. The price used in our assessment of future cash flows is based on our independent evaluators’ estimate of future prices and evaluated for reasonability by OPTI against other available information. We believe these prices are reasonable estimates for a long-term outlook. In addition, lower prices could be used without resulting in any additional impairment. Significantly lower price assumptions could result in a ceiling test impairment. Impairment would be recognized in earnings in the period in which capitalized costs exceeded estimated future cash flows.
Asset Retirement Obligations
We measure asset retirement obligations at each financial statement date. The estimate is based on our share of costs to reclaim the resource assets and certain facilities related to the Project as well as other resource assets associated with future phases. The liability is primarily related to reclamation of the SAGD facility and drilling assets. To determine the future value of the liability, we estimate the amount, timing and inflation of the associated abandonment costs. We then calculate the present value of the cost to record the current asset retirement obligation using a credit-adjusted risk-free rate. In some cases, due to the long-lived nature of the asset, the timing of future abandonment cannot be estimated and no asset retirement obligation is recorded. Due to the long-term nature of current and future project developments, abandonment costs will be incurred over many years in the future. As a result of these factors, different estimates could be used for such abandonment costs and the associated timing. Assumptions of higher future abandonment costs, higher inflation, lower credit-adjusted risk-free rates or an assumption of earlier or specified timing of abandonment would cause the asset retirement obligation and corresponding asset to increase. These changes would also cause future accretion expenses to increase and future earnings to decrease.
Future Taxes
We utilize the asset and liability method of accounting for income taxes under which future income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amount and the tax basis of assets and liabilities. In addition, an estimate is required for both the
23
timing and corresponding tax rate for this reversal. Should these estimates change, it may impact the measurement of our asset or liability as well as future tax recovery or expense recognized to earnings. These estimates do not impact our cash flow from operations. Where unfavourable evidence exists, which in our case is primarily historical net field operating losses, additional considerations and evidence for recognition of future tax assets is required. We have applied management judgment and evaluated applicable factors necessary in making this determination and have concluded that the positive evidence in consideration of the estimated future cash flows based on reserve reports from our independent engineers, does not sufficiently outweigh negative factors, such as our net field operating loss in 2009 and 2008 .. As a result, 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 of $149 million against our future tax assets.
Depletion, depreciation and accretion
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 these are key components to the calculation of depletion. A downward revision in the reserve estimate or an upward revision to future capital would result in increased depletion, reduced earnings and reduced net book value of SAGD assets. Major SAGD and Upgrader facilities are depreciated with the unit-of-production method based on the estimated productive capacity of the facilities over 40 years. A downward revision in the estimated productive capacity of the facilities would result in increased depreciation, reduced earnings and a reduced net book value of SAGD and Upgrader facilities.
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 materially impact our financial statements.
In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments – Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments will be effective for annual financial statements for fiscal years ending after September 30, 2009 and are consistent with recent amendments to financial instrument disclosure standards in IFRS. The adoption of this section enhances disclosures on our financial statements.
24
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 year-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.
25
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 recognition criteria in relation to PP&E, 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 of 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 of 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 applied 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.
26
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 plan to present this measure on a consistent basis from period to period. 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 years noted, the following is a reconciliation of earnings (loss) before taxes to net field operating margin (loss).
| $ millions | 2009 | 2008 | 2007 | |||||||||
| Earnings (loss) before taxes | $ | (234 | ) | $ | (593 | ) | $ | 159 | ||||
| Interest, net | 150 | 33 | (13 | ) | ||||||||
| General and administrative | 17 | 18 | 14 | |||||||||
| Financing charges | 22 | 1 | 12 | |||||||||
| Impairment related to asset sale | - | 369 | - | |||||||||
| Loss on disposal of assets | 1 | - | - | |||||||||
| Foreign exchange loss (gain) | (294 | ) | 373 | (235 | ) | |||||||
| Net realized loss (gain) on hedging instruments | (40 | ) | (116 | ) | - | |||||||
| Net unrealized loss (gain) on hedging instruments | 234 | (160 | ) | 61 | ||||||||
| Depletion, depreciation and accretion | 26 | 17 | 2 | |||||||||
| Net field operating margin (loss) | $ | (118 | ) | $ | (58 | ) | $ | - | ||||
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 December 31, 2009, the Company has no financial assets that are past due or impaired due to credit-risk-related defaults.
27
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. We mitigate liquidity risk by maintaining a sufficient cash balance, maintaining sufficient current and projected liquidity to meet expected future payments based upon 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 December 31, 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 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 December 31, 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 relate to future estimated prices for WTI.
For the year ended December 31, 2009, 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 $1 million increase in our net income with an offsetting decrease in the value of our commodity liabilities of approximately $1 million (assuming the WTI change occurred in a range where the WTI price per barrel is less than the strike price of our commodity put), a $0.10 increase in the price of natural gas would have resulted in approximately a $1 million decrease in net income, a 1.0% increase in interest rates would have resulted in approximately a $1 million decrease in net income and a $0.01 increase in the Canadian to U.S. exchange rate would increase our net income by approximately $10 million considering the impact on our Senior Notes 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 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 December 31, 2009 the amount in cash and cash equivalents was $358 million and the maximum exposure to a single counterparty was $81 million which is guaranteed by a major Canadian bank.
28
At December 31, 2009, the remaining terms on investments made by the Company are less than 38 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 and Other Receivables
Our accounts receivable include amounts due from Nexen. related to operating activities and Nexen Marketing related to marketing activities. At December 31, 2009, our accounts receivable due from Nexen includes $0.2 million related to operating activities and $11 million related to marketing 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.
We have prepaid $4 million of operating expenses related to insurance. These costs are amortized into earnings over the period of prepayment.
* Accounts Payable and Accrued Liabilities
As at December 31, 2009, accounts payable and accrued liabilities were $79 million. Accounts payable and accrued liabilities are comprised primarily of $65 million due in respect of development and operation of the Project, $11 million due in respect of interest on our Senior Notes and $3 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 December 31, 2009, long-term debt was $2,273 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 December 31, 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.
29
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 December 31, 2009, 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 $1.8 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 ”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 December 31, 2009. 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 December 31, 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 at a rate of approximately CDN$1.18 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 April 2010 (US$330 million) and December 2010 (US$545 million). 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$1.18 to US$1.00 on a portion of our debt. The foreign currency forwards at December 31, 2009 are a liability of $115 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.
Prior to the expiry of the foreign exchange forward in 2010, OPTI may choose 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 current expiry 2010. 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. The value of the
30
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 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 December 31, 2009 the Company has commodity price swaps that provide for 1.1 million barrels at strike prices between US$64/bbl and US$67/bbl of crude oil starting January 1, 2010 through December 31, 2010. The value of these financial instruments as at December 31, 2009 was a liability of $19 million. The counterparties to the commodity hedges are major Canadian and international banks. Our exposure to non-payment from any single institution is approximately 33 percent of the value of the commodity asset, which is due from 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 commodity hedges would change by approximately $1 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
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.
Market Risks
We are involved in a capital intensive industry. Oil sands development requires significant investment prior to any cash being returned to the business in the form of operating cash flow. The development cycle for each additional phase is expected to be greater than five years. We expect that significant external capital will be required. In addition, the occurrence of some or all of the following could require us to seek additional capital during 2010; poor operating results, requirement for major repairs or improvements to our facilities or low commodity prices. Recent volatility in the financial sector and the overall economy mean that such capital may be restricted in terms of size, expensive in historical terms, or not available at all. Although our current financial resources are expected to be
31
sufficient for 2010, there is no assurance that should we require additional capital we will be able to obtain such financing.
Risk Factors During Operations
* Oil Prices and Foreign Exchange
Our financial results and our ability to access external capital will be impacted by the current price and expectations related to the future price of crude oil. Oil prices fluctuate significantly in response to regional, national and global supply and demand factors beyond our control. Political and economic developments around the world can affect world oil demand, supply and oil prices. Over the last two years, monthly oil prices have experienced significant volatility with a peak of approximately US$130/bbl and a low of approximately US$40/bbl.
The Long Lake Upgrader will ultimately produce a fully upgraded product called PSCTM. The price we will receive for PSC™ will be dependent on the demand for it and will primarily be influenced by changes in the market price for WTI, which is influenced by global market factors. To a lesser extent, the price we receive for PSCtm will be affected by regional factors such as supply of other synthetic and conventional crude oils. Although we expect PSCtm to trade at a price similar to WTI, PSCtm is a relatively new synthetic crude oil product and limited assurance can be given as to its price and marketability. We have engaged Nexen Marketing, which has extensive experience in marketing synthetic crude, to sell all of our production from the Long Lake Project.
After the Long Lake Upgrader start-up and during periods when the Upgrader is not operating, including planned and unplanned maintenance and repair, we may be unable to upgrade the bitumen produced by the Project. During these periods, bitumen produced would be mixed with diluent and sold as a bitumen blend. The blend would be priced significantly lower than conventional light oil or PSCtm. We also plan to purchase third party bitumen and upgrade this bitumen into PSCtm using our Upgrader. While we expect these purchased barrels to be priced at a discount to WTI, this discount can vary considerably. Should this discount be lower than expected, such purchases will cost more than we expect which will reduce our net field operating margin.
Our future results of operations will be impacted by certain factors outside of our control, such as the gravity and quality of the bitumen produced from the Long Lake leases, which can ultimately determine the amount of syngas and PSCtm produced from the Long Lake Upgrader.
Crude oil prices are generally based on a U.S. dollar market price, while most of our operating and capital costs are denominated in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollars result in foreign currency exchange exposure. Therefore, changes in the exchange rate will affect the price we receive for PSCtm. We have protected a portion of this exposure to oil price fluctuation with our commodity hedges and have no hedges designed to address foreign exchange rates fluctuations related to the sale of our products. Over the last 2 years, the U.S. to Canadian exchange rate has experienced significant volatility ranging from approximately CDN$1.00 to US$1.00 in February 2008 to CDN$1.26 to US$1.00 in March 2009.
32
* Operating Risk
The performance of the SAGD operation and the Long Lake Upgrader may differ from our expectations. There are many factors related to the characteristics of the reservoir and SAGD operating facilities that could cause bitumen production to be lower than anticipated. The Long Lake Upgrader is comprised of a number of facilities that upgrade bitumen, in part using high pressure and temperature. There are inherent risks in the initial and ongoing operation of our facility. The processing of hydrocarbons requires intensive operating and execution expertise. Operating issues could result in increases to cost, reduced production or damage to facilities. All of these factors could negatively affect our results from operations.
Currently, the Long Lake Project represents our only producing asset and therefore our results depend exclusively on the performance of the Project. The performance of the SAGD operation and the Long Lake Upgrader is dependent on complex, inter-dependent facilities. The shut-down of any part of these facilities could significantly impact the production of PSCtm and/or bitumen. Causes of production shortfalls or interruptions may include, but are not limited to: bitumen constraints, equipment failure, design errors, operator errors, weather related shut-downs or other events such as an explosion or a fire. Extreme cold weather can affect the operations by reducing productivity, causing equipment failure and potentially increasing natural gas consumption. Major incidents or unscheduled outages may inhibit production and increase operating costs.
OPTI reduces exposure to some operational risks by maintaining appropriate levels of insurance, primarily business interruption (“BI”) and property insurance. We have purchased total coverage of US$2.0 billion of BI and property insurance (combined) in case Long Lake experiences an event causing a loss or interruption of production, such as a fire or explosion at the operating facilities. The BI insurance is subject to a 90-day waiting period and the property insurance contains a $10 million deductible ($3.5 million net to OPTI). While such insurance assists in mitigating some operational upsets, insurance is unlikely to fully protect against catastrophic events or prolonged shutdowns.
* Non-operator
Nexen is the operator of the Long Lake Project. We rely on Nexen’s operating expertise to generate cash flow from the Project and to provide information on the status and results of operations. There are no assurances that Nexen will be able to generate improved operating or financial results from the Project or that Nexen will be able to report financial and operational information on a timely basis. In addition, these financial results require Nexen to make estimations in regards to progress on capital and operating activities.
Our joint-venture agreement is designed to promote development of Long Lake Project and future phases. Major capital decisions for new projects require support from both OPTI and Nexen while other matters require only the approval of the operator. Historically, OPTI and Nexen have sought consensus on all significant matters however, there can be no assurance that future agreements will be reached with respect to future capital programs. The ability of either joint-venture partner to prevent future development is limited. If we are unable or choose not to participate in part or at all in future phases, we will forego our working interest in such phases and the associated
33
lands. We may recover only those costs spent to date which may be less than the fair market value of the foregone working interest.
* Reserves and Resources
There are numerous uncertainties inherent in estimating quantities of reserves and resources, including many factors beyond our control, and no assurance can be given that the indicated level of reserves or resources or recovery of bitumen will be realized. In general, estimates of resources and of economically recoverable bitumen reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates that have inherent uncertainties, the assumed effects of regulation by government agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially.
The estimates with respect to reserves and resources that may be developed and produced in the future have been based upon volumetric calculations and upon analogy to similar types of reserves and resources, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves and resources based upon production history will result in variations, which may be material, in the estimated reserves and resources.
Reserve and resource estimates may require revision based on actual production experience. Such figures have been determined based upon assumed oil prices and operating costs. Market fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. Also, short-term factors relating to oil sands resources may impair the profitability of the Project in any particular period.
Should the reserve estimate change in future periods, there could be a material impact on the fair value of our securities, our results of operations and our ability to obtain financing.
* Commodities Risk
During regular operations, our exposure to natural gas prices is reduced as the Long Lake Upgrader is expected to generate syngas, which will be used instead of natural gas. In the long-term, we expect most of our natural gas requirements will be generated by syngas with the remainder supplied from purchased natural gas. Although we expect stable Upgrader operations, during periods of Upgrader downtime we have significant exposure to natural gas prices. During these periods, virtually all of the energy required to generate steam for the SAGD operations will be from the purchase of natural gas. The amount of total natural gas required will be determined by our ability to generate syngas from our gasification unit and the SOR that is in our SAGD operation. If the SOR is higher than anticipated, we may be required to purchase natural gas beyond existing forecasted levels at prevailing market rates. This would cause our operating costs to increase and reduce our earnings.
34
During periods when the Upgrader is not in operation, we will be producing raw bitumen from the SAGD process. These bitumen barrels will be blended with a purchased diluent and sold as a bitumen blend. The price per barrel of purchased diluent will approximate WTI. The price we receive for this bitumen blend may vary widely and may be at a significant discount to WTI.
Project Development Risk
* Financing Risk
The development of oil sands projects in connection with the Project and our multi-stage expansion plan requires a significant amount of capital investment that occurs over a number of years. We currently do not have the financial resources or committed financing necessary to complete our future phases of development and we expect to require additional debt or equity financing to obtain the funds necessary to complete future phases. The cost or availability of additional financing may not make future phases economically feasible.
* Regulatory Risk
We are subject to extensive Canadian federal, provincial and local laws and regulations governing exploration, development, transportation, production, exports, occupational health, protection and reclamation of the environment, safety and other matters.
We are exposed to a risk of a negative impact of the Long Lake Project operations on the environment. We are committed to mitigate environmental impacts. The Long Lake Project operations involves the use of water and the emission of greenhouse gases therefore legislation that significantly restricts or penalizes current production or usage levels could have a material impact on our operations. The costs of meeting the environmental thresholds would increase operating costs and/or capital costs.
Completed phases of the Project will produce greenhouse gases (GHGs) and other industrial air pollutants. The Canadian federal government has released a framework that outlines proposed new requirements governing the emission of GHGs and other industrial pollutants. It is possible that new federal or provincial requirements with respect to GHGs and industrial air pollutants will be imposed. This may require additional funding or facilities to comply with such requirements. In addition, foreign regional or national governments could enact legislation that may result in a reduction in demand for our sales products based on environmental considerations. This could result in a reduction in the price we may receive for our products.
Environmental legislation regulating carbon fuel standards in jurisdictions that import crude and synthetic crude oil in the U.S. could result in increased costs and/or reduced revenue. For example, both the State of California and the United States federal government have passed legislation which, in some circumstances, considers the lifecycle greenhouse gas emissions of purchased fuel and which may negatively affect the marketing of our products, or require the purchase of emissions credits in order to complete sales in such jurisdictions.
35
We are currently required to pay a royalty to the Alberta government on our bitumen production. A royalty regime was implemented by Alberta effective January 1, 2009, which is sensitive to commodity prices and such regime, has been and may in the future be amended from time to time. Income tax laws or government incentive programs relating to the oil and gas industry may in the future be changed or interpreted in a manner that adversely affects us.
* Risks to Future Phase Development
We have announced phased development for up to five additional phases of projects of a similar size to the Project. The development of these phases is subject to a number of risks, primarily in the areas of resource extent and quality, cost, execution, long-term commodity price expectation and regulatory approval. If the estimates of costs to complete these future phases are higher than anticipated, these future phases may be deferred or cancelled. The execution of these future phases requires specialized labour, module construction, engineering expertise and construction management. Oil sands development in Alberta may be at high levels of activity when we decide to proceed with future phases, therefore some or all of these resources may not be available to us on the schedule that we require, which could delay future development. We do not have regulatory approval for all of these expansions. These regulatory approvals may delay or restrict our development of future phases.
* Infrastructure Risk
The Project will depend on successful operation of certain infrastructure owned and operated by others, including, without limitation:
| · | pipelines for the transportation of feedstocks and petroleum products to be sold ; |
| · | pipelines for the transportation of natural gas; |
| · | a railway spur for the transportation of products and by-products including sulphur; |
| · | disposal facilities for by-products of the Project (e.g. sulphur); and |
| · | electricity transmission systems for the provision and/or sale of electricity. |
The failure of any or all of these utilities to supply service will negatively impact the operation of the Project which may have a material adverse effect on our business or results of operations.
Revolving Credit Facility Covenant Risk
Continued access to our revolving credit facility is important to support our ongoing financial position as described more completely under “Liquidity and Capital Resources.” Failure to comply with our total debt to capitalization covenant 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 2010 are a decline in the value of the Canadian dollar relative to the U.S. dollar and poor or inconsistent Project operations.
In respect of new borrowings under the $190 million revolving credit facility, we are subject to various conditions precedent including the absence of any material adverse effect.
36
Strategic Alternatives Process Risk
Our board of directors has decided to assess a range of strategic alternatives available to OPTI that may include capital market opportunities, asset divestures and/or a corporate sale, merger or other business combination. There can be no assurance that any transaction will occur or, if a transaction is undertaken, as to its terms or timing.
37